Lilis Energy
Annual Report 2014

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 FORM 10-K ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2014 or ☐ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________to_________ Commission file number: 001-35330 Lilis Energy, Inc.(Name of registrant as specified in its charter) NEVADA 74-3231613(State or other jurisdiction ofincorporation or organization) (I.R.S. EmployerIdentification No.) 216 16th Street, Suite 1350, Denver, CO 80202(Address of principal executive offices, including zip code) Registrant’s telephone number including area code: (303) 893-9000 Securities registered under Section 12(b) of the Act: Common Stock, $0.0001 par value The Nasdaq Global MarketTitle of class Name of exchange on which registered Securities registered under Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ☐ No ☒ Indicate by check mark if the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during thepast 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required tobe submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period thatthe registrant was required to submit and post such files). Yes ☒ No ☐ Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to thebest of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment tothis Form 10-K. ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (asdefined in Rule 12b-2 of the Act): Large accelerated filer ☐Accelerated filer☐Non-accelerated filer ☐Smaller reporting company☒ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ State the aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price at which the commonequity was last sold, or the average bid and asked price of such common equity, as of the last business day of the fiscal quarter ended June 30,2014: $31,645,000 As of April 15, 2015, 26,988,240 shares of the registrant’s Common Stock were issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE Information relating to Part III of this report will be incorporated by reference from an amendment to this report or from the proxy statement for our 2015annual shareholders meeting, which we expect to file with the Securities and Exchange Commission within 120 days after December 31, 2014.  FORM 10-K ANNUAL REPORTFISCAL YEAR ENDED DECEMBER 31, 2014LILIS ENERGY, INC. PagePART I8Items 1 and 2. Business and Properties8Item 1A. Risk Factors22Item 1B. Unresolved Staff Comments35Item 3. Legal Proceedings35PART II37Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities37Item 6.Selected Financial Data38Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations38Item 7A.Quantitative and Qualitative Disclosures About Market Risk48Item 8. Financial Statements and Supplementary Data48Item 9.Changes in and disagreements with Accountants on Accounting and Financial Disclosure49Item 9A.Controls and Procedures49Item 9B.Other Information50PART III51Item 10.Directors, Executive Officers and Corporate Governance51Item 11.Executive Compensation51Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 51Item 13.Certain Relationships and Related Transactions, and Director Independence51Item 14.Principal Accountant Fees and Services51PART IV52Item 15.Exhibits and Financial Statement Schedules52 2 FORWARD-LOOKING STATEMENTS This annual report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements otherthan statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to, anyprojections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations; anystatements concerning future production, reserves or other resource development opportunities; any projected well performance or economics, or potentialjoint ventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements regarding future capital-raisingactivities; any statements of belief; and any statements of assumptions underlying any of the foregoing. Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “expect” or“anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this presentation. Exceptas required by law, we do not intend, and undertake no obligation, to update any forward-looking statement. Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from thoseprojected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-lookingstatements, are subject to change and inherent risks and uncertainties. The factors impacting these risks and uncertainties include, but are not limited to, theRisk Factors set forth in this Form 10-K in Part I, “Item 1A. Risk Factors” and the following factors: ●availability of capital on an economic basis, or at all, to fund our capital or operating needs; ●our level of debt, which could adversely affect our ability to raise additional capital, limit our ability to react to economic changes and make itmore difficult to meet our obligations under our debt; ●restrictions imposed on us under our credit agreement that limit our discretion in operating our business; ●failure to meet requirements or covenants under our debt instruments, which could lead to foreclosure of significant core assets; ●failure to fund our authorization for expenditures from other operators for key projects which will reduce or eliminate our interest in thewells/asset; ●our history of losses; ●inability to address our negative working capital position in a timely manner; ●the inability of management to effectively implement our strategies and business plans; ●potential default under our secured obligations, material debt agreements or agreements with our investors; ●estimated quantities and quality of oil and natural gas reserves; ●exploration, exploitation and development results; ●fluctuations in the price of oil and natural gas, including further reductions in prices that would adversely affect our revenue, cash flow, liquidityand access to capital; ●availability of, or delays related to, drilling, completion and production, personnel, supplies (including water) and equipment; ●the timing and amount of future production of oil and natural gas; ●the timing and success of our drilling and completion activity; ●lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements; ●declines in the values of our natural gas and oil properties resulting in write-down or impairments; ●inability to hire or retain sufficient qualified operating field personnel; ●our ability to successfully identify and consummate acquisition transactions; ●our ability to successfully integrate acquired assets or dispose of non-core assets; ●availability of funds under our credit agreement; ●increases in interest rates or our cost of borrowing; ●deterioration in general or regional (especially Rocky Mountain) economic conditions; ●the strength and financial resources of our competitors; ●the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or couldimpact the operations of companies or contractors we depend upon in our operations; 3 ●inability to acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts; ●inability to successfully develop our large inventory of undeveloped acreage we currently hold on a timely basis; ●constraints, interruptions or other issues affecting the Denver-Julesburg Basin, including with respect to transportation, marketing, processing,curtailment of production, natural disasters, and adverse weather conditions; ●technique risks inherent in drilling in existing or emerging unconventional shale plays using horizontal drilling and complex completiontechniques; ●delays, denials or other problems relating to our receipt of operational consents, approvals and permits from governmental entities and otherparties; ●unanticipated recovery or production problems, including cratering, explosions, blow-outs, fires and uncontrollable flows of oil, natural gas orwell fluids; ●environmental liabilities; ●operating hazards and uninsured risks; ●data protection and cyber-security threats; ●loss of senior management or technical personnel; ●litigation and the outcome of other contingencies, including legal proceedings; ●adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect toexisting operations, including those related to climate change and hydraulic fracturing; ●anticipated trends in our business; ●effectiveness of our disclosure controls and procedures and internal controls over financial reporting; ●changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate; and ●other factors, many of which are beyond our control. Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factorsthat may affect us. For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement,we urge you to carefully review and consider the disclosures made in the “Risk Factors” sections of our SEC filings, available free of charge at the SEC’swebsite (www.sec.gov). 4 GLOSSARY In this report, the following abbreviation and terms are used: Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude, condensate or natural gas liquids. Bcf. Billion cubic feet of natural gas. BOE. Barrels of crude oil equivalent, determined using the .ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids. BOE/d. BOE per day. Completion. Installation of permanent equipment for production of natural gas or oil, or in the case of a dry hole, the reporting to the appropriate authoritythat the well has been abandoned. Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure but that, when produced, is in theliquid phase at surface pressure and temperature. Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. Drilling locations. Total gross locations specifically quantified by management to be included in our multi-year drilling activities on existing acreage. Ouractual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs,drilling results and other factors. Dry well; dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in anotherreservoir. Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same geological structural feature and/orstratigraphic condition. Formation. An identifiable layer of subsurface rocks named after its geographical location and dominant rock type. Gross acres, gross wells, or gross reserves. A well, acre or reserve in which the Company owns a working interest, reported at the 100% or 8/8ths level. Forexample, the number of gross wells is the total number of wells in which the Company owns a working interest. Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on aparticular tract of land. Leasehold. Mineral rights leased in a certain area to form a project area. Mbbls. Thousand barrels of crude oil or other liquid hydrocarbons. Mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids. Mcf. Thousand cubic feet of natural gas. Mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids. 5 MMbtu. Million British Thermal Units. MMcf. Million cubic feet of natural gas. Net acres; net wells. A “net acre” or “net well” is deemed to exist when the sum of fractional ownership working interests in gross acres or wells equals one.The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells expressed as whole numbers and fractions ofwhole numbers. Ngl. Natural gas liquids, or liquid hydrocarbons found as a by-product of natural gas. Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses astandard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil andnatural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operatorsubject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of3/4. Overriding royalty interest owners have no financial or other obligation or responsibility for developing and operating the property. The only expensesborne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable. Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape intoanother or to the surface. Regulations of all states require plugging of abandoned wells. Production. Natural resources, such as oil or gas, flowed or pumped out of the ground. Productive well. A producing well or a well that is mechanically capable of production. Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certaintyto be economically producible – from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and governmentregulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardlessof whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operatormust be reasonably certain that it will commence the project within a reasonable time. Proved developed oil and gas reserves. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existingwells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well;and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving awell. Proved undeveloped reserves. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilledacreage, or from existing wells where a relatively major expenditure is required for recompletion. Project. A targeted development area where it is probable that commercial oil and/or gas can be produced from new wells. Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis usingreasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons. PV-10 (Present value of future net cash flow). The present value of estimated future revenues to be generated from the production of estimated provedreserves, net of capital expenditures and operating expenses, using the simple 12 month arithmetic average of first of the month prices and current costs(unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as generaland administrative expenses, debt service, future income tax expenses, depreciation, depletion and amortization or impairment, discounted using an annualdiscount rate of 10%. While this non-GAAP measure does not include the effect of income taxes as would the use of the standardized measure calculation, webelieve it provides an indicative representation of the relative value of Lilis Energy on a comparative basis to other companies and from period to period. 6 Recompletion. The process of re-entering an existing well bore that is either producing or not producing and modifying the existing completion and/orcompleting new reservoirs in an attempt to establish new production or increase or re-activate existing production. Reserves. Estimated remaining quantities of oil, natural gas and gas liquids anticipated to be economically producible, as of a given date, by application ofdevelopment projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right toproduce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financingrequired to implement the project. Reservoir. A subsurface formation containing a natural accumulation of producible natural gas and/or oil that is naturally trapped by impermeable rock orother geologic structures or water barriers and is individual and separate from other reservoirs. Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure or fluid drive of the reservoir, such as gas injection or waterflooding, to produce residual oil and natural gas remaining after the primary recovery phase. Shut-in. A well suspended from production or injection but not abandoned. Standardized measure. The present value of estimated future cash flows from proved oil and natural gas reserves, less future development, abandonment,production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as wereused to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. Successful. A well is determined to be successful if it is producing oil or natural gas in paying quantities. Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantitiesof oil or natural gas regardless of whether such acreage contains proved reserves. Water-flood. A method of secondary recovery in which water is injected into the reservoir formation to maintain or increase reservoir pressure and displaceresidual oil and enhance hydrocarbon recovery. Working interest. The operating interest that gives the lessees/owners the right to drill, produce and conduct operating activities on the property, and toreceive a share of the production revenue, subject to all royalties, overriding royalties and other burdens, all development costs, and all risks in connectiontherewith. 7 PART I Items 1 and 2. BUSINESS AND PROPERTIES Lilis Energy, Inc. (NASDAQ: LLEX) (“we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is a Denver-based upstream independent oil and gascompany engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. We were incorporated in August of 2007 in theState of Nevada as Universal Holdings, Inc. In October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name toLilis Energy, Inc. Our current operating activities are focused on the Denver-Julesburg Basin (“DJ Basin”) in Colorado, Wyoming and Nebraska. Our business strategy isdesigned to maximize shareholder value by leveraging the knowledge, expertise and experience of our management team and via the future exploration anddevelopment of the approximately 65,000 net acres of developed and undeveloped acreage that are currently held by us, primarily in the northern DJ Basin. Recent Developments As previously disclosed, we had significant developments in 2014 through the date of this report, including substantial management changes, theconsummation of private placement transactions in January and May of 2014 and the conveyance of the Hexagon Collateral (discussed below) to our primarylender Hexagon, LLC (“Hexagon”) in exchange for extinguishment of all outstanding debt and accrued interest obligations owed to Hexagon in Septemberof 2014. Additionally, we successfully completed a conversion of more than half of our outstanding 8% Senior Secured Convertible Debentures (the“Debentures”) in January of 2014. The Debentures (as previously amended) mature on January 15, 2015; however, in connection with our entry into theCredit Agreement (discussed below) in January 2015, we entered into an extension agreement with the holders of the Debentures, which extends the maturitydate of the outstanding Debentures until January 8, 2018. The maturity date now coincides with the maturity date of the Credit Agreement. For furtherdiscussion of our capital raising transactions, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of 2014 and Recent Developments, and the notes to our financial statements. Heartland Bank Credit Agreement On January 8, 2015, we entered into a credit agreement with Heartland Bank (the “Credit Agreement”) which provides for a three-year senior secured termloan in an initial aggregate principal amount of $3.0 million, which principal amount may be increased to a maximum principal amount of $50.0 million atthe request of us, subject to certain conditions, pursuant to an accordion advance provision in the Credit Agreement. The availability of additional funds issubject to the discretion of the lenders, and is generally based on the value of the Company’s proved developed producing (“PDP”) and proved undeveloped(“PUD”) reserves. We intends to use proceeds borrowed under the Credit Agreement to fund producing property acquisitions in North America, drill wells inthe core of our lease positions and to fund working capital. Overview of Our Business and Strategy We have acquired and developed a producing base of oil and natural gas proved reserves, as well as a portfolio of exploration and other undeveloped assetswith conventional and non-conventional reservoir opportunities, with an emphasis on those with multiple producing horizons, in particular the Muddy “J”conventional reservoirs and the Niobrara shale and Codell resource plays. We believe these assets offer the possibility of repeatable year-over-year successand significant and cost-effective production and reserve growth. Our acquisition, development and exploration pursuits are principally directed at oil andnatural gas properties in North America. Since early 2010, we have acquired and/or developed 25 producing wells. As of December 31, 2014 we ownedinterests in 8 economically producing wells and 67,000 gross (65,000 net) leasehold acres, of which 59,000 gross (57,000 net) acres are classified asundeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. We are primarily focused on acquiringcompanies and production throughout North America and developing our North and South Wattenberg Field assets, which include attractive unconventionalreservoir drilling opportunities in mature development areas with low risk Niobrara and Codell formation productive potential. Our intermediate goal is to create significant value via the investment of up to $50.0 million through acquisitions of producing assets and the developmentof our inventory of low and controlled-risk conventional and unconventional properties, while maintaining a low cost structure, and to acquire companiesand production or producing properties (typically with accompanying prospective development opportunity) throughout North America. To achieve this, ourbusiness strategy includes the following elements: Acquiring additional assets and companies throughout North America. We are targeting acquisitions in North America, which meet certain current andfuture production thresholds to increase shareholder value. We anticipate the acquisitions will be funded with funds borrowed under the Credit Agreementand equity to be accessed in capital markets transactions. 8 Pursuing the initial development of our Greater Wattenberg Field unconventional assets. We plan to drill several horizontal wells on our South Wattenbergproperty during 2015. Drilling activities will target the well established Niobrara and Codell formations. Subject to the securing of additional capital, weexpect to drill and operate up to 8 wells, with an expected investment of approximately $18.0 million. Extending the development of certain conventional prospects within our inventory of other DJ Basin properties. Subject to the securing of additionalcapital, we anticipate the expenditure of up to an additional $50.0 million in drilling and development costs on three of our DJ Basin assets where initialexploration has yielded positive results. Additional drilling activities will be conducted on each property in an effort to fully assess each property and definefield productivity and economic limits. Retain Operational Control and Significant Working Interest. In our principal development targets, we typically seek to maintain operational control ofour development and drilling activities. As operator, we retain more control over the timing, selection and process of drilling prospects and completiondesign, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of capitalexpenditures. However, due to our recent liquidity difficulties, a significant amount of our current drilling activity on wells in which we own an interest isnot operated by us. Leasing of Prospective Acreage. In the course of our business, we identify drilling opportunities on properties that have not yet been leased. Subject tosecuring additional capital, we may take the initiative to lease prospective acreage and we may sell all or any portion of the leased acreage to othercompanies that want to participate in the drilling and development of the prospect acreage. Hedging. From time to time, we use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensurethat we have adequate cash flow to fund our debt service costs and capital programs. As such, we will enter into futures contracts, collars and basis swapagreements, as well as fixed price physical delivery contracts. We intend to use hedging primarily to manage price risks and returns on certain acquisitionsand drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In the future wemay also be required by our lenders to hedge a portion of production as part of any financing. Acreage. Currently, our inventory of developed and undeveloped acreage includes approximately 8,000 net acres that are held by production,approximately, 49,000, 2,000, 5,000 and 1,000 net acres that expire in the years 2015, 2016, 2017, and thereafter, respectively. Approximately 88% of ourinventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of us, via payment of varying, but typicallynominal, extension amounts. We’re currently evaluating the 2015 lease expirations to determine if this acreage is a focus for future development. Ifdetermined to be a focus for future development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. We plan to borrow additionalfunds under the Credit Agreement to acquire additional bolt-on properties, acquire other properties throughout North America, or drill wells on our coreproperties to hold the property by production. Capital Raising. The business of oil and natural gas property acquisition, exploration and development is highly capital intensive and the level ofoperations attainable by oil and natural gas companies is directly linked to and limited by the amount of available capital. Therefore, a principal part of ourplan of operations is to raise the additional capital required to finance the exploration and development of our current oil and natural gas prospects and theacquisition of additional properties. We will need to raise additional capital to fund our exploration and development, and operating, budget. We plan toseek additional capital through the sale of our securities, through debt and project financing, joint venture agreements with industry partners, and throughsale of assets. Our ability to obtain additional capital through new debt instruments, project financing and sale of assets may be subject to the repayment ofour existing obligations. Outsourcing. We intend to continue to use the services of independent consultants and contractors to provide various professional services, including land,legal, environmental, technical, investor relations and tax services. We believe that by limiting our management and employee costs, we may be able tobetter control lifting costs and retain G&A flexibility. 9 Principal Oil and Gas Interests All references to production, sales volumes and reserve quantities are net to our interest unless otherwise indicated. As of December 31, 2014 we owned interests in approximately 67,000 gross (65,000 net) leasehold acres, of which 59,000 gross (57,000 net) acres areclassified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. Our primary targets within the DJBasin are the conventional Dakota and Muddy “J” formations, and the developing unconventional Niobrara shale play. Additional horizons include theCodell, Greenhorn and other potential resource formations. Effective as of December 31, 2014, we completed an assessment of our inventory of unevaluated acreage, which resulted in a transfer of $9.90 million fromunevaluated acreage to evaluated properties. In assessing the unevaluated acreage, we analyzed the expiration dates during the years ended December 31,2014 and 2015 of leases that are not otherwise renewable, and transferred such acreage in the amount of $6.99 million. In addition to the transfer of near andintermediate term expirations, we assessed carrying value of our remaining acreage, and concluded that an additional transfer of $2.91 million was necessary.No proved reserves were associated with the transferred acreage. During 2014, we made minimal capital expenditures on our oil and gas properties due to capital constraints. On September 2, 2014, we entered into a Final Settlement Agreement (defined below) to convey its interest in 31,725 evaluated and unevaluated net acreslocated in the DJ Basin and the associated oil and natural gas (the “Hexagon Collateral”) to its primary lender, Hexagon in exchange for extinguishment ofall outstanding debt and accrued interest obligations owed to Hexagon aggregating to $15.1 million. The conveyance assigned all assets and liabilitiesassociated with the property, which includes PDP and PUD reserves, plugging and abandonment, and other assets and liabilities associated with the property.Pursuant to the Final Settlement Agreement, we also issued to Hexagon $2.0 million in 6% Conditionally Redeemable Preferred Stock valued at $1.69million and considered as temporary equity for reporting purposes. See Item 7 Management Discussion and Analysis of Financial Condition and Results ofOperations—Overview of 2014 and Recent Developments —Hexagon Settlement and —Results of Operations—Loss on Conveyance of oil and gasproperties. Reserves The table below presents summary information with respect to the estimates of our proved oil and gas reserves for the year ended December 31, 2014. Weengaged Ralph E. Davis Associates, Inc. (“RE Davis”) to audit internal engineering estimates for 100 percent of our proved reserves at year-end 2014. Theprices used in the calculation of proved reserve estimates as of December 31, 2014, were $81.71 per Bbl and $5.34 per MCF; as of December 31, 2013, were$89.57 per Bbl and $4.74 per MCF and as of December 31, 2012, were $87.37 per Bbl and $2.75 per MCF for oil and natural gas, respectively. The priceswere adjusted for basis differentials, pipeline adjustments, and BTU content. 10 We emphasize that reserve estimates are inherently imprecise and that estimates of all new discoveries and undeveloped locations are more imprecise thanestimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. ThePV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by us. Neither prices nor costs have been escalated (or reduced). The following table should be read along with the section entitled “Risk Factors — Risks Relatedto Our Company”. The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated. As of December 31, 2014 2013 2012 Reserve data: Proved developed Oil (MBbl) 50 171 213 Gas (MMcf) 197 313 186 Total (MBOE)(1) 83 223 244 Proved undeveloped Oil (MBbl) 850 672 138 Gas (MMcf) 4,040 2,251 221 Total (MBOE)(1) 1,523 1,047 175 Total Proved Oil (MBbl) 900 843 351 Gas (MMcf) 4,237 2,564 407 Total (MBOE)(1) 1,606 1,270 419 Proved developed reserves % 5% 18% 58%Proved undeveloped reserves % 95% 82% 42% Reserve value data (in thousands): Proved developed PV-10 $2,340 $7,675 $9,743 Proved undeveloped PV-10 $20,914 $15,667 $5,679 Total proved PV-10 (2) $23,254 $23,342 $15,422 Standardized measure of discounted future cash flows $23,254 $23,342 $15,422 Reserve life (years) 39.25 33.25 42.42 (1)BOE is determined using the ratio of six MCF of natural gas to one Bbl of crude oil, condensate or natural gas.(2)As we currently do not expect to pay income taxes in the near future, there is no difference between the PV-10 value and the standardized measure ofdiscounted future net cash flows. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the“Glossary.” Changes in Proved Undeveloped Reserves The 476 MBOE or 45% increase of proved undeveloped reserves to 1,523 MBOE at year end 2014 from 1,047 MBOE at year end 2013 reflects, in part,additional proved undeveloped locations, partially offset by the 347 MBOE conveyed to Hexagon described in detail above. An acreage block owned by uswas determined to be proved undeveloped based on offset successful drilling activity of other operators. We did not incur any cost on our provedundeveloped acreage in 2014. Effective as of December 31, 2014, we completed an assessment of our inventory of unevaluated acreage, which resulted in a transfer of $9.90 million toevaluated properties. In assessing the unevaluated acreage, we analyzed its expiration dates during the years ended December 31, 2014 and 2015, which arenot otherwise renewable, and transferred such acreage in the amount of $6.99 million. In addition to the transfer of near and intermediate term expirations, weassessed the carrying value of our remaining acreage, and concluded that an additional transfer of $2.91 million was necessary. No proved reserves wereassociated with the transferred acreage. At December 31, 2014, we have no proved undeveloped reserves that are scheduled for development five years or more beyond the date the reserves wereinitially recorded. Internal Controls over Reserves Estimate Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserve quantities andvalues in compliance with the regulations of the SEC. Responsibility for compliance in reserve bookings is delegated to our Chief Financial Officer withassistance from our senior geologist consultant, principal accounting officer, and a senior reserve engineering consultant. 11 Technical reviews are performed throughout the year by our senior reserve engineering consultant and our geologist and other consultants who evaluate allavailable geological and engineering data, under the guidance of the Chief Financial Officer. This data, in conjunction with economic data and ownershipinformation, is used in making a determination of estimated proved reserve quantities. The 2014 reserve process was overseen by Kent Lina, our seniorreserve engineering consultant. Mr. Lina was previously employed by us from October 2010 through December 2012, and prior to that employed by DeltaPetroleum Corporation from March 2002 to September 2010 in various operations and reservoir engineering capacities culminating as the Senior V.P. ofCorporate Engineering. Mr. Lina received a Bachelor of Science degree in Civil Engineering from University of Missouri at Rolla in 1981. Mr. Linacurrently serves various industry clients as a senior reserve engineering consultant. Third-party Reserves Study An independent third-party reserve study as of December 31, 2014 was performed by RE Davis using its own engineering assumptions and other economicdata provided by us. One hundred percent of our total calculated proved reserve PV-10 value was audited by RE Davis. RE Davis is an independentpetroleum engineering consulting firm that has been providing petroleum engineering consulting services for over 20 years. The individual at RE Davisprimarily responsible for overseeing our reserve audit is Allen C. Barron, the President and CEO, who received a Bachelor of Science degree in Chemical andPetroleum Engineering from the University of Houston and is a registered Professional Engineer in the States of Texas. He is also a member of the Society ofPetroleum Engineers. The RE Davis report dated March 10, 2015, is filed as Exhibit 99.1 to this Annual Report. Oil and gas reserves and the estimates of the present value of future net cash flows therefrom were determined based on prices and costs as prescribed by theSEC and Financial Accounting Standards Board (“FASB”) guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil andgas and the timing and amount of future net cash flows to be received therefrom. Such estimates are not precise and are based on assumptions regarding avariety of factors, many of which are variable and uncertain. Proved reserves were estimated in accordance with guidelines established by the SEC and theFASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalationsexcept by contractual arrangements. For the year ended December 31, 2014, commodity prices over the prior 12-month period and year end costs were usedin estimating net cash flows in accordance with SEC guidelines. In addition to a third party reserve study, our reserves and the corresponding report are reviewed by our Chief Financial Officer, geologist and principalaccounting officer and the Audit Committee of our Board of Directors. Our Chief Financial Officer is responsible for reviewing and verifying that theestimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews the final reserves estimate in conjunction with RE Davis’audit letter. Production The following table summarizes the average volumes and realized prices, excluding the effects of our economic hedges, of oil and gas produced fromproperties in which we held an interest during the periods indicated. Also presented is a production cost per BOE summary: For the Year Ended December 31, 2014 2013 2012 Product Oil (Bbl.) 33,508 51,705 68.207 Oil (Bbls)-average price (1) $77.05 $83.40 $86.48 Natural Gas (MCF)-volume 77,954 64,845 182,160 Natural Gas (MCF)-average price (2) $4.68 $5.25 $2.23 Barrels of oil equivalent (BOE) 46,500 62,512 98,567 Average daily net production (BOE) 127 171 270 Average Price per BOE (1) $63.36 $74.43 $63.96 (1) Does not include the realized price effects of hedges(2) Includes proceeds from the sale of NGL's 12 Oil and gas production costs, production taxes, depreciation, depletion, and amortization Average Price per BOE (1) $63.36 $74.43 $63.96 Production costs per BOE $20.52 $19.48 $14.42 Production taxes per BOE $5.80 $4.21 $2.31 Depreciation, depletion, and amortization per BOE $28.76 $38.21 $46.15 Total operating costs per BOE (2) $55.08 $61.90 $62.88 Gross margin per BOE (2) $8.28 $12.53 $1.08 Gross margin percentage 13% 17% 2% (1) Does not include the realized price effects of hedges(2) Does not include the loss on conveyance Productive Wells As of December 31, 2014, after the conveyance on September 2, 2014, we had working interests in 6 gross (1.27 net) productive oil wells, and 2 gross (.14net) productive gas wells. Productive wells are either wells producing in commercial quantities or wells capable of commercial production althoughcurrently shut-in. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well ora gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production. Acreage As of December 31, 2014 we owned 8 producing wells in Wyoming, Nebraska and Colorado within the DJ Basin, as well as approximately 67,000 gross(65,000 net) acres, of which 59,000 gross (57,000 net) acres were classified as undeveloped acreage. Our primary assets included acreage located in Laramieand Goshen Counties in Wyoming; Banner, Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado. The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 2014. Undeveloped Developed Gross Net Gross Net DJ Basin 59,000 57,000 8,000 8,000 Total 59,000 57,000 8,000 8,000 At December 31, 2014, our inventory of developed and undeveloped acreage includes approximately 8,000 net acres that are held by production,approximately, 49,000, 2,000 and 5,000 and 1,000 net acres that expire in the years 2015, 2016, 2017, and thereafter, respectively. Approximately 89% ofour inventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of us, via payment of varying, but typicallynominal, extension amounts. We’re currently evaluating the 2015 lease expirations to determine if this acreage is a focus for future development. Ifdetermined to be a focus for future development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. We plan to borrow additionalfunds under the Credit Agreement and to seek additional debt or equity capital, if available, to acquire additional bolt-on properties, acquire other propertiesthroughout North America, or drill wells on our core properties to hold the property by production. 13 Drilling Activity The following table describes the development and exploratory wells we drilled from 2012 through 2014: For the Year Ended December 31, 2014 2013 2012 Gross Net Gross Net Gross Net Development: Productive wells - - 2 1 5 3 Dry wells - - - - 1 1 - - 2 1 6 4 Exploratory: Productive wells - - - - - - Dry wells - - - - - - Total development and exploratory - - 2 1 6 4 The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. As ofDecember 31, 2014, we had no drilling activities on-going. Title to Properties Substantially all of our leasehold interests are held pursuant to leases from third parties. The majority of our producing properties are subject to mortgagessecuring indebtedness under our Credit Agreement and Debentures, which we believe do not materially interfere with the use of, or affect the value of, suchproperties. Capital Budget We anticipate a capital budget of up to $50.0 million for 2015. The budget is allocated toward the acquisition of properties and companies in North Americaand to develop eight operated wells focused on unconventional reservoirs located in the Wattenberg field within the DJ Basin that will apply horizontaldrilling in the Niobrara shale and Codell formations. The entire capital budget is subject to the ability to secure additional capital through equity placement, utilizing borrowings under the Credit Agreementwith Heartland Bank and additional debt instruments and funds contemplated by the agreement with Heartland Bank to acquire production in North America. In addition to the need to secure adequate capital to fund our capital budget, the execution of, and results from, our capital budget are contingent on variousfactors, including, but not limited to, market conditions, oilfield services and equipment availability, commodity prices and drilling/ productionresults. Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget. Other factors that could impact ourlevel of activity and capital expenditure budget include, but are not limited to, a reduction or increase in service and material costs, the formation of jointventures with other exploration and production companies, and the divestiture of non-strategic assets. As of December 31, 2014 and December 31, 2013, we had $6.04 million and $1.15 million of wells in progress, respectively. Wells in progress are related tocertain wells in our core development program within the Northern Wattenberg field. We capitalized and accrued approximately $5.70 million of coststhrough December 31, 2014 associated with these wells, which are currently in dispute. The dispute relates to our interest in certain producing wells and the well operator’s assertion that the Company’s interest was reduced and/or eliminated as aresult of a default or a farm-out agreement. Underlying the dispute is a Joint Operating agreement (“JOA”), which provides the parties with various rights andobligations. On March 6, 2015, the Company filed a lawsuit against the operator. In its complaint, we seek monetary damages and declaratory relief on claims of breachof contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjustenrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint. 14 Marketing and Pricing We derive revenue and cash flow principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailingprices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Themarket price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil andnatural gas. Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may alsoaffect the amount of cash flow available for capital expenditures and other cash requirements and our ability to borrow money or raise additionalcapital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels ofnatural gas and crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuationsare: ●changes in global supply and demand for oil and natural gas; ●the actions of the Organization of Petroleum Exporting Countries, or OPEC; ●the price and quantity of imports of foreign oil and natural gas; ●acts of war or terrorism; ●political conditions and events, including embargoes, affecting oil-producing activity; ●the level of global oil and natural gas exploration and production activity; ●the level of global oil and natural gas inventories; ●weather conditions; ●technological advances affecting energy consumption; ●transportation options from trucking, rail, and pipeline; and ●the price and availability of alternative fuels. Furthermore, regional natural gas, condensate, oil and NGL prices may move independently of broad industry price trends. Because some of our operationsare located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. From time to time, we enter into derivative contracts. These contracts economically hedge our exposure to decreases in the prices of oil and natural gas.Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where: ●our production and/or sales of natural gas are less than expected; ●payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or ●the counterparty to the hedging contract defaults on its contract obligations. In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that anyhedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. As of December 31, 2014, we had no hedging agreements in place. Major Customers We have one major customer, Shell Trading (US), which accounted for approximately 63% and 83% of our revenues for the years ended December 31, 2014and 2013, respectively. PDC Energy, a new customer in 2014, accounted for 13% of our revenue for the year ended December 31, 2014. However, we does not believe that the loss of a single purchaser, including Shell Trading (US) and PDC Energy, would materially affect our business becausethere are numerous other purchasers in the area in which we sell our production. 15 Seasonality Generally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summer months. Tolessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forwardpurchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity has placed increaseddemand on storage volumes. Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season, although oil pricesare much more driven by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. The impact ofseasonality on crude oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of production capacity inexcess of existing worldwide demand for crude oil. Competition The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe our leaseholdposition provides a solid foundation for an economically robust exploration program and our future growth. Our success and growth also depends on ourgeological, geophysical, and engineering expertise, design and planning, and our financial resources. We believe the location of our acreage, our technicalexpertise, available technologies, our financial resources and expertise, and the experience and knowledge of our management enables us to competeeffectively in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies,which have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition,exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, andgenerate electricity. We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling,completion, production, processing and maintenance of wells. Consequently, we may face shortages or delays in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may also be affected by future new energy, climate-related, financial, and other policies, legislation, and regulations. In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals and consultants. Throughout the oiland gas industry, the need to attract and retain talented people has grown at a time when the number of talented people available is constrained. We are notinsulated from this resource constraint, and we must compete effectively in this market in order to be successful. Government Regulations General. Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and local laws andregulations. The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impact ouroperations and can affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different than ourcompetitors. Matters regulated include permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wellsand unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements for the operation of wells,production and processing facilities, land use, subsurface injection, air emissions, and taxation of production, etc. At various times, regulatory agencies haveimposed price controls and limitations on production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow ofoil and natural gas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regardingproduction. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil andnatural gas and other substances and materials produced or used in connection with oil and natural gas operations. While we believe we will be able tosubstantially comply with all applicable laws and regulations via our strict attention to regulatory compliance, the requirements of such laws and regulationsare frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect on our actual operations. Federal Income Tax. Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject tocertain limitations, to deduct as incurred, rather than to capitalize and amortize/depreciate, our domestic “intangible drilling and development costs” and toclaim depletion on a portion of our domestic oil and natural gas properties based on 15% of our oil and natural gas gross income from such properties (up toan aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas). 16 Environmental, Health, and Safety Regulations. Our operations are subject to stringent federal, state, and local laws and regulations relating to theprotection of the environment and human health and safety (“EHS”). We are committed to strict compliance with these regulations and the utmost attentionto EHS issues. Environmental laws and regulations may require that permits be obtained before drilling commences or facilities are commissioned, restrictthe types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities,govern the handling and disposal of waste material, and limit or prohibit drilling and exploitation activities on certain lands lying within wilderness,wetlands, and other protected areas, including areas containing threatened or endangered animal species. As a result, these laws and regulations maysubstantially increase the costs of exploring for, developing, or producing oil and gas and may prevent or delay the commencement or continuation of certainprojects. In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligations in the event of any discharges oremissions in violation of these laws and regulations. Further, legislative and regulatory initiatives related to global warming or climate change could have anadverse effect on our operations and the demand for oil and natural gas. See “Risk Factors — Risks Related to the Oil and Gas Industry — Legislative andregulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.” Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tightunconventional formations. For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors— Risks Relating to theOil and Gas Industry.” Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additionaloperating restrictions or delays /cancellations in the completion of oil and gas wells. Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, or producedin our operations. Some of this information must be provided to our employees, state and local governmental authorities, and local citizens. We are alsosubject to the requirements and reporting framework set forth in the federal workplace standards. The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us toincur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well ordrilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden dischargesfrom damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to fresh water aquifers or adjoiningproperty, giving rise to additional liabilities. A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing. Theselaws and regulations may impose liability in the event of discharges, including for accidental discharges, failure to notify the proper authorities of adischarge, and other noncompliance. Compliance with such laws and regulations may increase the cost of oil and gas exploration, development andproduction; although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to complywith the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanentcurtailment or cessation of all or a portion of our operations. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability,regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardoussubstance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies thattransport, dispose, or arrange for disposal of the hazardous substance(s) released. Persons who are or were responsible for releases of hazardous substancesunder CERCLA may be jointly and severally liable for the costs of cleaning up the hazardous substances and for damages to natural resources. It is notuncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardoussubstances released into the environment. We could be subject to liability under CERCLA, including for jointly owned drilling and production activitiesthat generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA. 17 The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”) is the principal federal statute governing the treatment, storage and disposal ofsolid and hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a“generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRAincludes an exemption that allows certain oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemptionis contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s hazardous wasterequirements. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas explorationand production wastes from regulation as hazardous waste. For example, in 2010 a petition was filed by the Natural Resources Defense Council with theEnvironmental Protection Agency (“EPA”) requesting that the agency reassess its prior determination that certain E&P wastes are not subject to the RCRAhazardous waste requirements. EPA has not yet acted on the petition and it remains pending. Repeal or modification of the exemption by administrative,legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we arerequired to manage and dispose of and would cause us to incur, perhaps significantly, increased operating expenses. The Oil Pollution Act of 1990 (“OPA”), and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oilspills and liability for damages resulting from such spills in United States waters. The OPA assigns liability to each responsible party for oil removal costsand a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a party cannot takeadvantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction oroperating regulations. Few defenses exist to the liability imposed by OPA. In addition, to the extent we acquire offshore leases and those operations affectstate waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws. OPA also imposes ongoingrequirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. We cannot predict whether thefinancial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or impose substantial additional annualcosts to us or otherwise materially adversely affect us. The impact, however, should not be any more adverse to us than it will be to other similarly situatedowners or operators. The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitats through theimplementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas. Additionally, significant federal decisions, such as theissuance of federal permits or authorizations for certain oil and gas exploration and production activities may be subject to the National EnvironmentalPolicy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential tosignificantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potentialdirect, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may bemade available for public review and comment. This process has the potential to delay oil and gas development projects. The federal Clean Water Act (the “Clean Water Act”), imposes restrictions and controls on the discharge of produced waters and other oil and natural gaswastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to discharge fill and pollutants into regulatedwaters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and willcontinue to complicate and increase the cost of, obtaining such permits or other approvals. Certain state regulations and the general permits issued under theFederal National Pollutant Discharge Elimination System (“NPDES”) program prohibit the discharge of produced waters and sand, drilling fluids, drillcuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the EPA, has adoptedregulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may beassociated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. Spill Prevention, Control, andCountermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls, piping controls, berms and other measuresto help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. The EPA and U.S. Army Corps ofEngineers released a Connectivity Report in September 2013, which determined that virtually all tributary streams, wetlands, open water in floodplains andriparian areas are connected. This report supported the drafting of proposed rules providing updated standards for what will be considered jurisdictionalwaters of the U.S. The proposed rules have been submitted for public comment, and are expected to be finalized in 2015. The Clean Water Act andcomparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of crude oil and other pollutants and imposeliability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resourcedamages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and statestatutes enacted to control water pollution. 18 The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for the underground injection of a variety of wastes, including bringproduced and separated from crude oil and natural gas production, with the main goal being the protection of usable aquifers. The primary objective ofinjection well operating permits and requirements is to ensure the mechanical integrity of the wellbore and to prevent migration of fluids from the injectionzone into underground sources of drinking water. Class II underground injection wells, a predominant storage method for crude oil and natural gaswastewater, are strictly controlled, and certain wastes, absent an exemption, cannot be injected into such wells. Failure to abide by our permits could subjectus to civil or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state undergroundinjection control programs and our permits. The federal Clean Air Act (the “Clean Air Act”) and comparable state and local air pollution laws adopted to fulfill its mandate provide a framework fornational, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state airpollution control laws. These laws generally require utilization of air emissions control equipment to achieve prescribed emissions limitations and ambientair quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. We believe that we arein compliance in all material respects with the requirements of applicable federal and state air pollution control laws. Over the next several years, we may berequired to incur capital expenditures for air pollution control equipment or other air emissions-related issues. EPA promulgated significant New SourcePerformance Standards (“NSPS OOOO”) in 2012, as amended in 2013 and 2014, which have added administrative and operational costs. EPA is reconsideringportions of NSPS OOOO and this process may result in additional federal control requirements. Colorado adopted NSPS OOOO in 2014. In addition,Colorado adopted new air regulations for the oil and gas industry effective April 14, 2014, that impose control and other requirements more stringent thanNSPS OOOO. These new Colorado oil and natural gas air rules will likely increase our administrative and operational costs. On December 17, 2014, the EPA proposed to revise and lower the existing 75 ppb national ambient air quality standard (“NAAQS”) for ozone under thefederal Clean Air Act to a range within 65-70 ppb. EPA is also taking public comment on whether the ozone NAAQS should be revised as low as 60 ppb. Alowered ozone NAAQS in a range of 60-70 ppb could result in a significant expansion of ozone nonattainment areas across the United States, including areasin which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increase regulatory burdens in the form of morestringent emission controls, emission offset requirements, and increased permitting delays and costs. There are numerous state laws and regulations in the states in which we operate which relate to the environmental aspects of our business. These state lawsand regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and gas activities, the conduct of salt waterdisposal operations, and the methods of plugging and abandonment of oil and gas wells which have been unproductive. Numerous state laws and regulationsalso relate to air and water quality. In 2014, Colorado Governor Hickenlooper created the Task Force on State and Local Regulation of Oil and Gas Operations (“Task Force”) to providerecommendations regarding the state and local regulation of oil and gas operations. The Task Force provided its final recommendations on February 27,2015, which include recommendations for future Colorado rulemakings or legislation to address, among others, local government collaboration with oil andgas operators, operator registration requirements with local governments and submission of operational information for incorporation into localcomprehensive plans, and creation of an oil and gas information clearinghouse. We cannot predict the ultimate outcome of the Task Force’srecommendations. Additionally, the Colorado Oil and Gas Conservation Act was amended in 2014 to increase the potential sanctions for violating the Act or its implementingregulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate a $10,000maximum penalty for violations that do not result in significant waste of oil and gas resources, damage to correlative rights, or adverse impact to publichealth, safety, or welfare; require the Colorado Oil and Gas Conservation Commission (“COGCC”) to assess a penalty for each day there is evidence of aviolation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations resulting fromgross negligence or knowing and willful misconduct. In 2015, the COGCC, consistent with the amendments to the Act, amended its regulations governingenforcement and penalties. We cannot predict how such regulatory amendments will ultimately affect the penalties assessed by the COGCC in futureenforcement cases involving us. We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry. We believe ourpresent activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you thatenvironmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwiseadversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution,environmental risks, generally are not fully insurable. 19 In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable forenvironmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuingviolations or contamination not discovered during our assessment of the acquired properties. Federal Leases. For those operations on federal oil and gas leases, such operations must comply with numerous regulatory restrictions, including variousnon-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued byvarious federal agencies. In addition, on federal lands in the United States, the Office of Natural Resources Revenue (“ONRR”) prescribes or severely limitsthe types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, ONRR prohibitsdeduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the ONRR has beenengaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculatingroyalties owed to the government. The natural gas and crude oil industry as a whole has resisted the proposed rules under an assumption that royalty burdenswill substantially increase. We cannot predict what, if any, effect any new rule will have on our operations. Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management (“BLM”). Theseleases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permitsrequired from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among otherthings, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, theremoval of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may require our operations onfederal leases to be suspended or terminated. In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior toleasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas whereintensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased the amount of time andregulatory costs necessary to obtain oil and gas leases administered by the BLM. In addition, the BLM, on March 20, 2015, issued its final regulations forhydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flowback and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land.The new regulations become effective on June 24, 2015. BLM has also announced its intention to conduct a separate rulemaking to address venting andflaring of natural gas from oil and gas operations on public land. These hydraulic fracturing-related rulemakings may adversely affect our operationsconducted on federal lands. Other Laws and Regulations. Various laws and regulations require permits for drilling wells and also cover spacing of wells, the prevention of waste ofnatural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well asother regulations that could be promulgated by the jurisdictions, in which we have production, could be to limit the number of wells that could be drilled onour properties and to limit the allowable production from the successful wells completed on our properties, thereby limiting our revenues. To date we have not experienced any material adverse effect on our operations from obligations under environmental, health, and safety laws andregulations. We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and thatcontinued compliance with existing requirements will not have a materially adverse impact on us. Employees As of December 31, 2014, we had three full-time employees and no part-time employees. Subsequent to year end, we added two employees, including KevinNanke as Chief Financial Officer and Ariella Fuchs as General Counsel. For the foreseeable future, we intend to only add additional personnel as ouroperational requirements grow. In the interim, we plan to continue to leverage the use of independent consultants and contractors to provide variousprofessional services, including land, legal, engineering, geology, environmental and tax services. We believe that by limiting our management andemployee costs, we are able to better control total costs and retain flexibility in terms of project management. 20 Executive Officers of the Company Our executive officers of the Company at the time of this filing are as follows: Name Age Office (1) First Elected to Present OfficeAbraham “Avi” Mirman 45 Chief Executive Officer (2) April 21, 2014Kevin Nanke 50 Executive Vice President and Chief Financial Officer (3) March 6, 2015Eric Ulwelling 36 Principal Accounting Officer and Controller (4) February 1, 2012Ariella Fuchs 33 General Counsel (5) March 16, 2015 (1)Executive officers are elected for one-year terms at the annual organizational meeting of the Board of Directors (the “Board”), which follows the annualmeeting of stockholders. (2)Mr. Mirman currently serves as our Chief Executive Officer, and has held that position since April 21, 2014. Prior to being appointed to his currentposition of Chief Executive Officer, Mr. Mirman served as our President beginning in September 2013. Mr. Mirman served as the Managing Director,Investment Banking at TR Winston from April 2013 until September 2014. Between 2012 and February 2013, he served as Head of Investment Bankingat John Thomas Financial, and between 2011 and 2012, he served as Head of Investment Banking at BMA Securities. Between 2006 and 2011, Mr.Mirman served as Chairman of the Board of Cresta Capital Strategies LLC. Mr. Mirman has extensive experience in financial and securities matters,including in obtaining financing for and providing financial advisory services to micro-cap public companies, including oil and gas and other energycompanies. Mr. Mirman graduated from the State University of New York at Buffalo with a B.S. in Political Science. (3)On March 6, 2015, the Board appointed Kevin Nanke to the position of Executive Vice President and Chief Financial Officer, effective immediately. Mr.Nanke, age 50, served as the President of KN Consulting, Inc., a consulting firm focused on the energy, real estate and restaurant industries, from 2012 to2015. Previously, Mr. Nanke served as the Treasurer and Chief Financial Officer of Delta Petroleum Corporation (“Delta”) from 1999 to 2012, and as itsController from 1995 to 1999. At the same time, Mr. Nanke served as Treasurer and Chief Financial Officer of Amber Resources, an exploration andproduction (“E&P”) subsidiary of Delta, and as Treasurer, Chief Financial Officer and Director of DHS Drilling Company, a drilling company that was50% owned by Delta. Prior to joining Delta, Mr. Nanke was employed by KPMG LLP, a global audit, tax and advisory firm. Mr. Nanke received aBachelor of Arts degree in Accounting from the University of Northern Iowa in 1989 and is a Certified Public Accountant (inactive). (4)Eric Ulwelling, who served as our Chief Financial Officer prior to the appointment of Mr. Nanke, ceased to serve in that role but continues on to serve asour’s Principal Accounting Officer and Controller. Mr. Ulwelling was appointed by the Board to the position of Chief Financial Officer in October 2014.Mr. Ulwelling joined us in 2012, serving as our Controller and Principal Accounting Officer until he was appointed to the position of Acting ChiefFinancial Officer in May 2014. From 2009-2011, Mr. Ulwelling served as a controller with Applied Natural Gas Fuels, Inc. From 2006 to 2009, heworked as an auditor with Singer Lewak, servicing publicly traded companies, and prior to that worked as an auditor with Pannell Kerr Forster. Mr.Ulwelling received a Bachelor of Science in Accounting from California State University of Fullerton, in 2002. (5)Ariella Fuchs was most recently an associate with Baker Botts L.L.P. from April 2013 to February 2015, specializing in securities transactions andcorporate governance. Prior to joining Baker Botts L.L.P, she served as an associate at White & Case LLP and Dewey and LeBoeuf LLP from January2010 to March 2013 in their mergers and acquisitions groups. Ms. Fuchs received a J.D. degree from New York Law School and a B.A. degree in PoliticalScience from Tufts University. Available Information Our executive offices are located at 216 16th Street, Suite 1350, Denver, Colorado 80202, and our telephone number is (303) 893-9000. Our web site iswww.lilisenergy.com. Additional information that may be obtained through our web site does not constitute part of this annual report on Form 10-K. Ourannual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are accessible free of charge at ourwebsite. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings atwww.sec.gov. 21 ITEM 1A.RISK FACTORS Investing in our shares involves significant risks, including the potential loss of all or part of your investment. These risks could materially affect ourbusiness, financial condition and results of operations and cause a decline in the market price of our shares. You should carefully consider all of the risksdescribed in this annual report, in addition to the other information contained in this annual report, before you make an investment in our shares. Inaddition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that could cause ourfuture results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in anyforward-looking statement. Some of these important factors, but not necessarily all important factors, include the following: Risks Related to Our Company Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in theeconomy or our industry and prevent us from meeting our obligations under our indebtedness. As of December 31, 2014, our total outstanding debt underour convertible debentures equaled $6.84 million. We currently have a three-year senior secured term loan in an initial aggregate principal amount of $3.0million. We also have a $2.0 million mandatory redeemable preferred stock currently valued at $1.69 million. While transactions in 2014 have significantlyreduced our debt, our degree of leverage could have important consequences, including the following: ●it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt servicerequirements, acquisitions and general corporate or other purposes; ●a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will notbe available for other purposes, including our operations, capital expenditures and future business opportunities; ●the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations; ●as we have pledged most of our oil and natural gas properties and the related equipment, inventory, accounts and proceeds as collateral for theborrowings under our credit facility, they may not be pledged as collateral for other borrowings and would be at risk in the event of a defaultthereunder; ●it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that haveless debt; ●we are vulnerable in the present downturn in general economic conditions and in our business, and we will likely be unable to carry out capitalspending and exploration activities that are currently planned; and ●we may from time to time be out of compliance with covenants under our term loan agreements, which will require us to seek waivers from ourlenders, which may be difficult to obtain. We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop our properties tothe extent desired. A higher level of indebtedness and/or preferred stock increases the risk that we may default on our obligations. Our ability to meet ourdebt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices andfinancial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors that will affectour ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets, thenumber of shares of capital stock we have authorized, unissued and unreserved and our performance at the time we need capital. Our inability to access additional capital in significant amounts as needed, may result in our inability to develop our current prospects and properties,cause us to forfeit our interest in certain prospects and inhibit our ability to develop our business. We plan to seek to obtain additional capital through thesale of our equity or debt securities, the successful deployment of our cash on hand, bank lines of credit, joint ventures, and project financing. Consequently,there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will becommercially reasonable. Currently, a significant portion of our revenue after field level operating expenses is required to be paid to our lenders as debtservice. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties,may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price could bematerially adversely affected. 22 We have historically incurred losses and cannot assure investors as to future profitability. We have historically incurred losses from operations during ourhistory in the oil and natural gas business. We had a cumulative deficit of approximately $147.82 million and $115.53 million as of December 31, 2014 and2013, respectively. Many of our properties are in the exploration stage, and to date we have established a limited volume of proved reserves on ourproperties. Our ability to be profitable in the future will depend on successfully addressing our near-term capital need to refinance our term loanindebtedness and fund our 2015 capital budget, and implementing our acquisition, exploration, development and production activities, all of which aresubject to many risks beyond our control. Even if we become profitable on an annual basis, we cannot assure you that our profitability will be sustainable orincrease on a periodic basis. We will require additional capital in order to achieve commercial success and, if necessary, to finance future losses from operations as we endeavor tobuild revenue, but we do not have any commitments to obtain such capital and we cannot assure you that we will be able to obtain adequate capital as andwhen required. The business of oil and gas acquisition, drilling and development is capital intensive and the level of operations attainable by an oil and gascompany is directly linked to and limited by the amount of available capital. We believe that our ability to achieve commercial success and our continuedgrowth will be dependent on our continued access to capital either through the additional sale of our equity or debt securities, bank lines of credit, projectfinancing, joint ventures, sale or lease of undeveloped acreage, or cash generated from oil and gas operations. We will seek to obtain additional capitalthrough the sale of our equity or debt securities, the successful deployment of our cash on hand, bank lines of credit, joint ventures, and projectfinancing. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of anyavailable financing will be commercially reasonable. If we are unable to access additional capital in significant amounts as needed, we may not be able todevelop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. Insuch an event, our stock price could be materially adversely affected. We have limited management and staff and will be dependent upon partnering arrangements. We had three employees at the end of December 31,2014. Subsequent to year end, we hired Kevin Nanke as our Chief Financial Officer and Ariella Fuchs as our General Counsel. We leverage the services ofindependent consultants and contractors to perform various professional services, including engineering, oil and gas well planning and supervision, andland, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospectgeneration, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but notlimited to: ●the possibility that such third parties may not be available to us as and when needed; and ●the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects. If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock pricecould be materially adversely affected. The loss of our Chief Executive Officer or Chief Financial Officer could adversely affect us. We are dependent on the experience of our executive officers toguide the implementation of our operational objectives and growth strategy. The loss of the services of any of these individuals could have a negativeimpact on our operations and our ability to implement our strategy. Our executive employment contracts include long term incentives to retain key personnelbut retention of personnel is not guaranteed. Our disclosure controls and procedures and internal controls over financial reporting may not detect errors or potential acts of fraud. Our management,including our chief executive officer and chief financial officer, does not expect that our disclosure controls and procedure and internal controls will preventall possible errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that theobjectives of the control system are being met. In addition, the design of a control system must reflect the fact that there are resource constraints, and thebenefit of controls are evaluated relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provideabsolute assurance that all control issues and instances of fraud, if any, have been detected. The design of any system of controls is based in part upon thelikelihood of future events, and there can be no assurance that any design will succeed in achieving its intended goals under all potential future conditions.Over time, a control may become inadequate because of changes in conditions, or the degree of compliance with its policies or procedures may deteriorate.Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection. Failure to maintain an effective system of internal control over financial reporting may have an adverse effect on our stock price. Pursuant to Section 404of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the Securities and Exchange Commission, or the SEC, to implement Section404, we are required to furnish a report by our management to include in our annual report on Form 10-K regarding the effectiveness of our internal controlover financial reporting. The report includes, among other things, an assessment of the effectiveness of our internal control over financial reporting as of theend of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must includedisclosure of any material weaknesses in our internal control over financial reporting identified by management. 23 We may discover areas of our internal control over financial reporting which may require improvement. If we are unable to assert that our internal controlover financial reporting is effective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internalcontrols, we could lose investor confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price. In addition to acquiring producing properties, we expect to also attempt to grow our business through the acquisition and development of exploratory oiland gas prospects, which is the riskiest method of establishing oil and gas reserves. In addition to acquiring producing properties, we expect to acquire,drill and develop exploratory oil and gas prospects that may or may not be profitable to produce. Developing exploratory oil and gas properties requiressignificant capital expenditures and involves a high degree of financial, technical and operational risk. The budgeted costs of drilling, completing, andoperating exploratory wells are often exceeded due to subsurface uncertainties and can increase significantly when market drilling costs rise. Drilling may beunsuccessful for many reasons, including unexpected geological issues, poor reservoir quality, title problems, weather, cost overruns, equipment shortages,and operational/mechanical difficulties. Moreover, the successful drilling or completion of an exploratory oil or gas well does not ensure a profit oninvestment. Exploratory wells bear a much greater investment and operational risk than development wells. We cannot assure you that our exploration,exploitation and development activities will result in profitable operations. If we are unable to successfully identify, acquire and develop commercial,exploratory oil and gas prospects, our results of operations, financial condition and stock price may be materially adversely affected If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, wells in progress are deemed unsuccessful, or major tracts ofundeveloped acreage expire, or other similar adverse events occur, we may be required to write-down the carrying value of our developed properties. Weuse the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into asingle cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling wells, completing productive wells, or plugging and abandoning non-productive wells, costs related to expired leases,or leases underlying producing and non-producing wells, and overhead charges directly related to acquisition and exploration activities. Under the full costmethod of accounting, capitalized oil and natural gas property that comprise the full cost pool, less accumulated depletion and net of deferred income taxes,may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves. Thisceiling test is performed at least quarterly. Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize impairment expense. During the year ended December 31, 2014, we did not recognize an impairment charge. Future write-downs could occur for numerous reasons, including, butnot limited to reductions in oil and gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserveestimates, or from the addition of non-productive capitalized costs to the full cost pool that do not result in corresponding increase in oil and gas reserves. Impairments of undeveloped acreage and plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full costpool, without any corresponding increase in reserve values; as such, these situations could result in future additional impairment expenses. If commodity prices stay at current early 2015 levels or decline further, we will incur full cost ceiling impairments in future quarters. Because the ceilingcalculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 2015 compared to 2014 is a lower ceilingvalue each quarter. This will result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges would not affect cash flow fromoperating activities, but would adversely affect our net income and stockholders’ equity. Hedging transactions may limit our potential gains or result in losses. In order to manage our exposure to price risks in the marketing of our oil and naturalgas, from time to time, we may enter into derivative contracts that economically hedge our oil and gas price on a portion of our production. These contractsmay limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, such transactionsmay expose us to the risk of financial loss in certain circumstances, including instances in which: ●there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received; ●our production and/or sales of oil or natural gas are less than expected; ●payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or ●the other party to the hedging contract defaults on its contract obligations. 24 Hedging transactions we may enter into may not adequately protect us from declines in the prices of oil and natural gas. In addition, the counterparties underour derivatives contracts may fail to fulfill their contractual obligations to us. As of December 31, 2014, we had no hedging agreements in place. Our large inventory of undeveloped acreage and large percentage of undeveloped proved reserves may create additional economic risk. Our success islargely dependent upon our ability to develop our large inventory of future drilling locations, undeveloped acreage and undeveloped reserves. As ofDecember 31, 2014, approximately 95% of our total proved reserves and 88% of our total acreage were undeveloped. To the extent our drilling results arenot as successful as we anticipate, natural gas and oil prices decline, or sufficient funds are not available to drill these locations and reserves, we may notcapture the expected or projected value of these properties. As previously disclosed, 49,000 of our 57,000 undeveloped acres are subject to lease expirationsin 2015. We are currently evaluating the 2015 lease expirations to determine if this acreage is a focus for future development. If determined to be a focus forfuture development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. In addition, delays in the development of our reserves orincreases in costs to drill and develop such reserves will reduce the economic PV-10 value of and delay cash flow from our estimated proved undevelopedreserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations. Significantgrowth in the size and scope of our operations would place a strain on our financial, technical, operational and management resources. The failure tocontinue to upgrade our technical, administrative, operating and financial staff and control systems or the occurrences of unexpected expansion difficulties,including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry could have amaterial adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan. The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, the present value of future net cash flowfrom our proved reserves will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves. This annualreport contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves contained in our filings with theSEC. The reserve estimate included in this annual report was prepared by our current reserve engineer consultant, reviewed by our Chief Financial Officer andPrincipal Accounting Officer/Controller and audited by RE Davis. The process of estimating oil and natural gas reserves is complex and requires significantdecisions and assumptions in the evaluation of available geological, geophysical, engineering, cost basis, commodity pricing and economic data for eachreservoir. Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development andoperating expenses, and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variationsmay be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates ofproved reserves to reflect production history, results of exploration and development drilling, results of secondary and tertiary recovery applications,prevailing oil and natural gas prices and other factors, many of which are beyond our control. You should also not assume that our initial rates of productionof our wells are representative of future overall production from other wells or over the life of the wells, or that early results suggesting lack of reservoircontinuity will prove to be accurate. You should not assume that the present value of future net cash flow referred to in this annual report is the current market value of our estimated oil andnatural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on theun-weighted average of the closing prices during the first day of each of the year preceding the end of the fiscal year. Actual future prices and costs may bematerially higher or lower than the prices and costs as of the date of the estimate. Any change in global markets consumption by oil or natural gas purchasersor in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from thedevelopment and production of our oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their presentvalue. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, isnot necessarily the most appropriate discount factor nor does it necessarily reflect discount factors used in the marketplace to assess asset values for thepurchase and sale of oil and natural gas. 25 Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine reserve potential, identify liabilitiesassociated with the properties or obtain protection from sellers against them, which could cause us to incur losses. One of our growth strategies is topursue selective acquisitions of undeveloped acreage potentially containing oil and natural gas reserves. If we choose to pursue an acquisition, we willperform a review of the target properties; however, these reviews are inherently incomplete as they are based on the quality, availability and interpretation ofthe reviewed data, the acumen and the assumptions of the evaluation personnel. Generally, it is not feasible to review in depth every individual property,well, facility and/or file involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potentialproblems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform aninspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection isundertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and wemay assume environmental and other risks and liabilities in connection with the acquired properties. All of our producing properties and operations are located in the DJ Basin region, making us vulnerable to risks associated with operating in one majorgeographic area. All of our estimated proved reserves at December 31, 2014, and all of our 2014 and 2013 sales were generated in the DJ Basin insoutheastern Wyoming, northeastern Colorado and southwestern Nebraska. Although the area is a well-established oilfield infrastructure, as a result, we maybe disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints,curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weatherconditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition,the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the DJ Basin,which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolioof properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our resultsof operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have amaterial adverse effect on our financial condition and results of operations. The marketability of our production is dependent upon transportation and processing facilities over which we may have no control. The marketability ofour production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, rail service, and processing facilitiesin addition to competing oil and gas production available to 3rd party purchasers. We deliver crude oil and natural gas produced from these areas throughtrucking, gathering systems and pipelines, some of which we do not own. The lack of availability of capacity on third-party systems and facilities couldreduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.Although we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems andfacilities may be temporarily unavailable due to market conditions or mechanical reliability or other reasons, including adverse weather conditions or work-loads. Activist or other efforts may delay or halt the construction of additional pipelines or facilities. Third-party systems and facilities may not be availableto us in the future at a price that is acceptable to us. Any significant change in market factors or other conditions affecting these infrastructure systems andfacilities, as well as any delays in constructing new infrastructure systems and facilities, could delay production, thereby harming our business and, in turn,our results of operations, cash flows, and financial condition. Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequatesupplies of water for our drilling and completion operations. Drilling and completion activities require the use of water. For example, the hydraulicfracturing process requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide asource of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amountsof water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Our success is influenced by oil, natural gas, and NGL prices in the specific areas where we operate, and these prices may be lower than prices at majormarkets. Regional natural gas, condensate, oil and NGLs prices may move independently of broad industry price trends. Because some of our operations arelocated outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. Unless we find new oil and gas reserves to replace actual production, our reserves and production will decline, which would materially and adverselyaffect our business, financial condition and results of operations. Producing oil and gas reservoirs generally are characterized by declining production ratesand depletion that vary depending upon reservoir characteristics subsurface and surface pressures and other factors. Thus, our future oil and gas reserves andproduction and, therefore, our cash flow and revenue are highly dependent on our success in efficiently obtaining additional reserves. We may not be able todevelop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business,financial condition and results of operations would be materially and adversely affected. 26 Part of our strategy involves drilling in existing or emerging unconventional shale plays using available horizontal drilling and completion techniques.The results of our planned exploratory and development drilling in these plays are subject to drilling and completion execution risks and drilling resultsmay not meet our economic expectations for reserves or production. As a result, we may incur material write-downs and the value of our undevelopedacreage could decline if drilling results are unsuccessful. Unconventional operations involve utilizing drilling and completion techniques as developed byourselves and our service providers. Risks that we face while drilling include, but are not limited to, not reaching the desired objective due to drillingproblems, not landing our wellbore in the desired drilling zone or specific target, staying in the desired drilling zone while drilling horizontally through theformation, running our casing the entire length of the wellbore and being able to run tools and other equipment consistently through the horizontalwellbore. Risks that we face while completing our wells include, but are not limited to, mechanical integrity, being able to fracture stimulate the plannednumber of stages, being able to run tools the entire length of the wellbore during completion operations, proper design and engineering vs. reservoirparameters, and successfully cleaning out the wellbore after completion of the final fracture stimulation stage. Our experience with horizontal well applications utilizing the latest drilling and completion techniques specifically in the Niobrara and/or Codell formationsis limited; however, we contract local experts in the area to design, plan and conduct our drilling and completion operations. Ultimately, the success of thesedrilling and completion techniques can only be developed over time as more wells are drilled and production profiles are established over a sufficiently longtime period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations,access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areasmay not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and the value of our undeveloped acreage coulddecline in the future. The unavailability or high cost of drilling rigs, equipment supplies or personnel could adversely affect our ability to execute our exploration anddevelopment plans. The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualifiedpersonnel. During these periods, the costs of and demand for rigs, equipment and supplies may increase substantially and their availability may belimited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in serviceincreases. The higher prices of oil and gas during the last several years have increased activity which has resulted in shortages of drilling rigs, equipment andpersonnel, which have resulted in increased costs and delays in the areas where we operate. If drilling rigs, equipment, supplies or qualified personnel areunavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially andadversely affected and, as a result, our financial condition and results of operations could be materially and adversely affected. Covenants in our Credit Agreement impose significant restrictions and requirements on us. Our Credit Agreement contains a number of covenantsimposing significant restrictions on us, including the maximum monthly payment requirement, restrictions on our repurchase of, and payment of dividendson, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets andcreate liens on our assets. These restrictions may affect our ability to operate our business, to take advantage of potential business opportunities as they ariseand, in turn, may materially and adversely affect our business, financial conditions and results of operations. We could be required to pay liquidated damages to some of our investors due to our failure to maintain the effectiveness of a prior registrationstatement. We could accrue liquidated damages under registration rights agreements covering a significant amount of shares of Common Stock if ourinvestors declare a default, due to our failure to maintain the effectiveness of a prior registration statement as required in the agreements. In such case, wewould be required to pay monthly liquidated damages. If we do not make a monthly payment within seven days after the date payable, we are required to payinterest at an annual rate of 18% on the unpaid amount. If our investors declare a default under the registration rights agreement and accrue liquidateddamages, we could be required to either raise additional outside funds through financing or curtail operations. We are exposed to operating hazards and uninsured risks. Our operations are subject to the risks inherent in the oil and natural gas industry, including therisks of: ●fire, explosions and blowouts; ●negligence of personnel, ●Weather ●pipe or equipment failure; ●abnormally pressured formations; and ●environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment(including groundwater contamination). 27 These events may result in substantial losses to us from: ●injury or loss of life; ●significantly increased costs; ●severe damage to or destruction of property, natural resources and equipment; ●pollution or other environmental damage; ●clean-up responsibilities; ●regulatory investigation; ●penalties and suspension of operations; or ●attorney's fees and other expenses incurred in the prosecution or defense of litigation. We maintain insurance against some, but not all, of these risks. We cannot assure you that our insurance will be adequate to cover these losses orliabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverseeffect on our financial condition and operations. The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanicalfailures, contract terms, pipeline and processing plant interruptions, market conditions, operator priorities, and weather conditions, etc. and weatherconditions. These curtailments can last from a few days to many months. Failure to adequately protect critical data and technology systems could materially affect our operations. Information technology solution failures,network disruptions and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing oftransactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation.There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operationsor cash flows. We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult. We periodically evaluateacquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. Thesuccessful acquisition of producing properties requires an assessment of several factors, including: ●recoverable reserves; ●future oil and natural gas prices and their appropriate differentials; ●well and facility integrity; ●development and operating costs; ●regulatory constraints and plans; and ●potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties. Our reviewwill not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies andpotential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable evenwhen an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protectionagainst all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is"basis. Significant acquisitions and other strategic transactions may involve other risks, including: ●diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions; ●challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those ofours while carrying on our ongoing business; ●difficulty associated with coordinating geographically separate organizations; ●challenge of attracting and retaining capable personnel associated with acquired operations; and ●failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or otherbenefits anticipated from an acquisition, or to realize these benefits within the expected time frame. 28 The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our seniormanagement and other staff may be required to devote considerable amounts of time to this integration process, which will decrease the time they will haveto manage our business. If our senior management and staff are not able to effectively manage the integration process, or if any significant business activitiesare interrupted as a result of the integration process, our business could suffer. Prospects in which we decide to participate may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targetedrate of return. A prospect is a property in which we own an interest and contains what we believe, based on available reservoir, seismic and/or geologicalinformation, to be indications of commercial oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to bedrilled to a prospect that will require substantial additional technical assessment, data acquisition and/or seismic data processing and interpretation. There isno definitive method to predict in advance of drilling and testing and wider-scale development whether any particular prospect will yield oil or natural gas insufficient quantities to be economically viable. The use of reservoir, geologic and seismic data and other technologies and the study of producing fields inthe same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas willbe present in commercial quantities. We cannot assure you that the analysis we perform using data from other wells, more fully explored prospects orproducing fields will be useful in predicting the characteristics and potential reserves associated with our drilling prospects. Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlyingassumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is complex. Itrequires interpretations of available technical data and many assumptions, including assumptions ranging from subsurface parameters to economic/marketfactors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the presentvalue of reserves shown in these reports. In order to prepare reserve estimates in its reports, our independent petroleum consultant projected production rates and timing of developmentexpenditures. Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data. The extent, qualityand reliability of this data can vary and may not be in our control. The process also requires economic assumptions about matters such as oil and natural gasprices, drilling and operating expenses, capital expenditures, infrastructure, taxes and availability of funds. Therefore, estimates of oil and natural gasreserves are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil andnatural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value ofour reserves. In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results,prevailing oil and natural gas prices and other factors, many of which are beyond our control due in-part to SEC guidelines. Risks Relating to the Oil and Gas Industry Oil and natural gas prices are highly volatile, and our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additionalcapital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas. Historically, the markets foroil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production and the levelsof our production depend on numerous factors beyond our control. These factors include the following: ●changes in global supply and demand for oil and natural gas; ●the actions of the Organization of Petroleum Exporting Countries (“OPEC”); ●the price and quantity of imports of foreign oil and natural gas; ●acts of war or terrorism; ●political conditions and events, including embargoes, affecting oil-producing activity; ●the level of global oil and natural gas exploration and production activity; ●the level of global oil and natural gas inventories; ●weather conditions; ●technological advances affecting energy consumption; ●the price and availability of alternative fuels; and ●market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives. 29 Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market foroil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for andproject the return on acquisitions and development and exploitation projects. Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gasthat we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Inaddition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affectour financial position, financial results, cash flows, access to capital and ability to grow. Our industry is highly competitive, which may adversely affect our performance, including our ability to participate in ready to drill prospects in our coreareas. We operate in a highly competitive environment. In addition to capital, the principle resources necessary for the exploration and production of oil andnatural gas are: ●leasehold prospects under which oil and natural gas reserves may be discovered; ●drilling rigs and related equipment to explore for such reserves; and ●knowledgeable personnel to conduct all phases of oil and natural gas operations. We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these competitors havefinancial and other resources substantially greater than ours. We cannot assure you that such capital, materials and resources will be available whenneeded. If we are unable to access capital, material and resources when needed, we risk suffering a number of adverse consequences, including: ●the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests; ●loss of reputation in the oil and gas community; ●inability to retain staff; ●inability to attract capital; ●a general slowdown in our operations and decline in revenue; and ●decline in market price of our common shares. We may face difficulties in securing and operating under authorizations and permits to drill, complete or operate our wells. The recent growth in oil andgas exploration in the United States has drawn intense scrutiny from environmental and community interest groups, regulatory agencies and othergovernmental entities. As a result, we may face significant opposition to, or increased regulation of, our operations that may make it difficult or impossible toobtain permits and other needed authorizations to drill, complete or operate, result in operational delays, or otherwise make oil and gas exploration morecostly or difficult than in other countries. Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oiland natural gas. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangermentto public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and otherclimatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases underexisting provisions of the CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires areduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationarysources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in theUnited States on an annual basis, including petroleum refineries, as well as certain onshore oil and natural gas production facilities. 30 EPA is also considering direct regulation of methane emissions from oil and gas facilities. On January 14, 2015, the White House and EPA indicated that theyplan to amend 40 C.F.R Part 60, Subpart OOOO (Subpart OOOO) standards to achieve additional methane and volatile organic compound reductions from theoil and natural gas industry. These potential amendments to Subpart OOOO could result in additional regulatory requirements and standards for completionsof hydraulically fractured oil wells, pneumatic pumps, and leaks from new and modified oil and gas exploration, production, and gathering facilities. Aproposed rule is expected in 2015, with a final rule expected in 2016. In June 2014, the United States Supreme Court’s holding in Utility Air Regulatory Group v. EPA upheld a portion of EPA’s GHG stationary source permittingprogram, but also invalidated a portion of it. The Court held that stationary sources already subject to the Prevention of Significant Deterioration (“PSD”) orTitle V permitting programs for non-GHG criteria pollutants remain subject to GHG Best Available Control Technology (“BACT”) and major sourcepermitting requirements, but ruled that sources cannot be subject to the PSD or Title V major source permitting programs based solely on GHG emissionlevels. Upon remand, EPA is considering how to implement the Court’s decision. The Court’s holding does not prevent states from considering and adoptingstate-only major source permitting requirements based solely on GHG emission levels. In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half ofthe states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gasemission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources ofemissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emissionallowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as coststo purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any suchlegislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs, and natural gas weproduce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financialcondition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in theEarth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, andfloods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operatingrestrictions or delays in the completion of oil and natural gas wells. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rockformations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulateproduction by providing and linking up induced flow paths for the oil and/or gas contained in the rocks. We routinely use hydraulic fracturing techniques inmany of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federalregulatory authority over certain hydraulic fracturing activities involving diesel fuel under the federal Safe Drinking Water Act. In addition, legislation hasbeen introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of thechemicals used in the hydraulic fracturing process. Under the proposed legislation, this information would be available to the public via the internet, whichcould make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals usedin the fracturing process could adversely affect groundwater. As discussed above, the BLM, on March 20, 2015, issued its final regulations for hydraulicfracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back andproduced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. The newregulations become effective on June 24, 2015. In addition, EPA intends to propose regulations in 2015 under the federal Clean Water Act to developstandards for wastewater discharges from hydraulic fracturing and other natural gas production activities. At the state level, some states have adopted, andother states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements onhydraulic fracturing activities. Some counties in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gasdevelopment, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyondthat, in 2012, Longmont, Colorado prohibited the use of hydraulic fracturing. The oil and gas industry filed a lawsuit challenging that ban in court. Theindustry prevailed on summary judgment against Longmont and the environmental intervenors. That decision is currently on appeal. In November 2013, fourother Colorado cities and counties passed voter initiatives either placing a moratorium on hydraulic fracturing or banning new oil and gas development.These initiatives too are the subject of pending legal challenge or appeal. While these initiatives cover areas with little recent or ongoing oil and gasdevelopment, they could lead opponents of hydraulic fracturing to push for statewide referendums, especially in Colorado. If new or more stringent federal,state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant addedcosts to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhapseven be precluded from drilling wells. 31 The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and a committee of theU.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, orhave been requested to review, environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmentaleffects of hydraulic fracturing on drinking water and groundwater, with draft results expected by 2015.. These ongoing studies, depending on their degree ofpursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or otherregulatory mechanisms. EPA has also issued an advance notice of proposed rulemaking and initiated a public participation process under the Toxic Substances Control Act (“TSCA”)to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms forobtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that EPA add the oiland gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Emergency Planning and CommunityRight-to-Know Act’s (“EPCRA”) Toxics Release Inventory (“TRI”) program. We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business. Our operations are subject toextensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, and operating safety. Futurelaws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements mayresult in substantial penalties and harm to our business, results of operations and financial condition. We may be required to make large and unanticipatedcapital expenditures to comply with governmental regulations, such as: ●land use restrictions; ●lease permit restrictions; ●drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds; ●spacing of wells; ●unitization and pooling of properties; ●safety precautions; ●operational reporting; and ●taxation. Under these laws and regulations, we could be liable for: ●personal injuries; ●property and natural resource damages; ●well reclamation cost; and ●governmental sanctions, such as fines and penalties. Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements orrestrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is also possible that aportion of our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequatelycompensated. See “Business and Properties—Government Regulations” for a more detailed description of our regulatory risks. Our operations may incur substantial expenses and resulting liabilities from compliance with environmental laws and regulations. Our oil and natural gasoperations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment orotherwise relating to environmental protection. These laws and regulations: ●require the acquisition of a permit before drilling or facility mobilization and commissioning, or injection or disposal commences; 32 ●restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and productionand processing activities, including new environmental regulations governing the withdrawal, storage and use of surface water or groundwaternecessary for hydraulic fracturing of wells; ●limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and ●impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in: ●the assessment of administrative, civil and criminal penalties; ●incurrence of investigatory or remedial obligations; and ●the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, storage, transport,disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a materialadverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental lawsand regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless ofwhether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Ourpermits require that we report any incidents that cause or could cause environmental damages. See “Business and Properties—Government Regulations” for amore detailed description of our environmental risks. Risks Relating to Our Common Stock There is a limited public market for our shares and we cannot assure you that an active trading market or a specific share price will be established ormaintained. Our Common Stock trades on the Nasdaq Global Market, generally in small volumes each day. The value of our Common Stock could beaffected by: ●actual or anticipated variations in our operating results; ●changes in the market valuations of other oil and gas companies; ●announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments; ●adoption of new accounting standards affecting our industry; ●additions or departures of key personnel; ●sales of our Common Stock or other securities in the open market; ●actions taken by our lenders or the holders of our convertible debentures; ●changes in financial estimates by securities analysts; ●conditions or trends in the market in which we operate; ●changes in earnings estimates and recommendations by financial analysts; ●our failure to meet financial analysts’ performance expectations; and ●other events or factors, many of which are beyond our control. In a volatile market, you may experience wide fluctuations in the market price of our Common Stock. These fluctuations may have an extremely negativeeffect on the market price of our Common Stock and may prevent you from obtaining a market price equal to your purchase price when you attempt to sellour Common Stock in the open market. In these situations, you may be required either to sell at a market price which is lower than your purchase price, or tohold our Common Stock for a longer period of time than you planned. An inactive market may also impair our ability to raise capital by selling shares ofcapital stock and may impair our ability to acquire other companies or oil and gas properties by using Common Stock as consideration. We may not satisfy the NASDAQ Capital Market’s requirements for continued listing. If we cannot satisfy these requirements, NASDAQ could delist ourCommon Stock. Our Common Stock is listed on the NASDAQ Capital Market, under the symbol LLEX. To continue to be listed on NASDAQ, we are requiredto satisfy a number of conditions. In past years, we defaulted on several of these requirements and regained compliance only after we carried out capital-raising and other transactions. We cannot assure you that we will be able to satisfy the NASDAQ listing requirements in the future. If we are delisted fromNASDAQ, trading in our Common Stock may be conducted, if available, on the “OTC Bulletin Board Service” or, if available, via another market. In theevent of such delisting, an investor would likely find it significantly more difficult to dispose of, or to obtain accurate quotations as to the value of ourCommon Stock, and our ability to raise future capital through the sale of our Common Stock or other securities convertible into our Common Stock could beseverely limited. In addition, if our Common Stock were delisted from NASDAQ, our Common Stock could be considered a “penny stock” under the U.S.federal securities laws. Additional regulatory requirements apply to trading by broker-dealers of penny stocks that could result in the loss of an effectivetrading market for our Common Stock. 33 Our Common Stock may be subject to penny stock rules which limit the market for our Common Stock. The SEC has adopted Rule 15g-9 which establishesthe definition of a “penny stock,” for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exerciseprice of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require: ●that a broker or dealer approve a person’s account for transactions in penny stocks; and ●that broker or dealer receives from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock tobe purchased. In order to approve a person’s account for transactions in penny stocks, the broker or dealer must: ●obtain financial information and investment experience objectives of the person; and ●make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge andexperience in financial matters to be capable of evaluating the risks of transactions in penny stocks. The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stockmarket, which, in highlight form: ●sets forth the basis on which the broker or dealer made the suitability determination; and ●that the broker or dealer received a signed, written agreement from the investor prior to the transaction. Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissionspayable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor incases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in theaccount and information on the limited market in penny stocks. Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors todispose of our Common Stock and cause a decline in the market value of our stock. Sales of a substantial number of shares of our Common Stock, or the perception that such sales might occur, could have an adverse effect on the price ofour Common Stock. As of December 31, 2014, six investors each hold more than 5% beneficial ownership of our Common Stock, and together, holdbeneficial ownership of approximately 75% of our Common Stock. Thus, any sales by our large investors of a substantial number of shares of our CommonStock into the public market, or the perception that such sales might occur, could have an adverse effect on the price of our Common Stock. We may issue shares of preferred stock with greater rights than our Common Stock. Our articles of incorporation authorize our board of directors to issueone or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stockthat is issued may rank ahead of our Common Stock, in terms of dividends, liquidation rights and voting rights. We currently have two series of preferredstock issued and outstanding, both of which provide its holders with a liquidation preference and prohibit the payment of dividends on junior securities,including our Common Stock, amongst other preferences and rights. There may be future dilution of our Common Stock. If we sell additional equity or convertible debt securities, such sales could result in increased dilution toour existing stockholders and cause the price of our outstanding securities to decline. To the extent outstanding warrants or options to purchase CommonStock under our employee and director stock option plans are exercised, the price vesting triggers under the performance shares granted to our executiveofficers are satisfied, or additional shares of restricted stock are issued to our employees, holders of our Common Stock will experience dilution. 34 We do not expect to pay dividends on our Common Stock. We have never paid dividends with respect to our Common Stock, and we do not expect to payany dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, the credit agreementrelating to our credit facility prohibits us from paying any dividends and the indenture governing our senior notes restricts our ability to pay dividends. Inthe future, we may agree to further restrictions. Our Common Stock is an unsecured equity interest in our Company. As an equity interest, our Common Stock is not secured by any of our assets. Therefore,in the event we are liquidated, the holders of the Common Stock will receive a distribution only after all of our secured and unsecured creditors have beenpaid in full. There can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution to theholders of the Common Stock. Securities analysts may not initiate coverage of our shares or may issue negative reports, which may adversely affect the trading price of the shares. Wecannot assure you that securities analysts will cover our company. If securities analysts do not cover our company, this lack of coverage may adversely affectthe trading price of our shares. The trading market for our shares will rely in part on the research and reports that securities analysts publish about us and ourbusiness. If one or more of the analysts who cover our company downgrades our shares, the trading price of our shares may decline. If one or more of theseanalysts ceases to cover our company, we could lose visibility in the market, which, in turn, could also cause the trading price of our shares todecline. Further, because of our small market capitalization, it may be difficult for us to attract securities analysts to cover our company, which couldsignificantly and adversely affect the trading price of our shares. Item 1B.UNRESOLVED STAFF COMMENTS Not applicable. Item 3.LEGAL PROCEEDINGS The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, theCompany’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’sgeneral and administrative expenses would include amounts incurred to resolve claims made against the Company. Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene in garnishmentproceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant, Tracinda, served various writs ofgarnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock. The Companyasserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. The underlyingjudgment against Mr. Parker was appealed to the Colorado Court of Appeals and, by Order dated October 17, 2013, that Court reversed the trial court withrespect to Mr. Parker’s claims of waiver, estoppel and mitigation of damages and remanded with instruction to enter judgment for Mr. Parker. The Court ofAppeals also ordered the trial court to conduct further proceedings to determine the amount of damages to award Mr. Parker on his breach of contract claim.The trial court conducted a later hearing and found in its Findings of Fact, Conclusions of Law and Order dated January 9, 2015, in favor of Mr. Parker on hisclaim for breach of contract, awarding him $6,981,302.60. Tracinda’s Motion for Amendment of the Court’s January 9 Findings and Conclusions is pending. In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No.13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-011301 EEB) against the Company and Roger Parker inconnection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property inconnection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10,2013. A trial date has not been set and, by Order dated February 2, 2015, the Bankruptcy Court ordered that the Adversary Proceeding be held in abeyancepending final resolution of the state-court action (2011CV561). The Company is unable to predict the timing and outcome of this matter. 35 Lilis Energy, Inc. v. Great Western Operating Company LLC, Eighth Judicial District Court for Clark County, Nevada, Case No. A-15-714879-B. On March 6,2015, the Company filed a lawsuit against the operator. The dispute relates to the Company’s interest in certain producing wells and the well operator’sassertion that the Company’s interest was reduced and/or eliminated as a result of a default or a farm-out agreement. Underlying the dispute is the JOA whichprovides the parties with various rights and obligations. In its complaint, the Company seeks monetary damages and declaratory relief on claims of breach ofcontract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjustenrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint. The Company believes there is no other litigation pending that could have, individually or in the aggregate, a material adverse effect on its results ofoperations or financial condition. Item 4.MINE SAFETY DISCLOSURES Not applicable. 36 PART II Item 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITYSECURITIES Recent Market Prices On November 2, 2011 our Common Stock began trading on the Nasdaq Global Market under the symbol "RECV." Between September 25, 2009 andNovember 1, 2011 our stock traded on the OTC Bulletin Board under the symbol "RECV.OB." On December 1, 2013, in connection with our name changesour Common Stock began trading on the Nasdaq Global Market under the symbol "LLEX." The following table shows the high and low reported sales prices of our Common Stock for the periods indicated. High Low 2014 Fourth Quarter $2.20 $0.62 Third Quarter $2.48 $1.02 Second Quarter $3.30 $1.73 First Quarter $3.58 $2.06 2013 Fourth Quarter $2.74 $1.64 Third Quarter $2.55 $1.42 Second Quarter $1.88 $1.34 First Quarter $2.35 $1.52 On April 13, 2015, there were approximately 84 owners of record of our Common Stock. Dividend Policy We have never paid any cash dividends on our Common Stock and do not anticipate paying any dividends in the foreseeable future. Our current businessplan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at thediscretion of our Board, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as our board maydeem relevant at that time. Limitations upon the Payment of Dividends The Company filed a Certificate of Designation of Preferences, Rights and Limitations of Series A 8% Convertible Preferred Stock (the “Certificate ofDesignation”) on May 30, 2014 with the Secretary of State of the State of Nevada, which was effective upon filing. The Certificate of Designation providesthat the holders of the Series A Preferred are entitled to receive a dividend payable at the election of the Company at a rate of 8% per annum. In addition, theCertificate of Designation provides that so long as the Series A Preferred remains outstanding, neither the Company nor any subsidiary of the Company maydirectly or indirectly pay or declare any dividend or make any distribution upon or in respect of any Junior Securities (as that term is defined in theCertificate of Designation) as long as any dividends due on the Series A Preferred remain unpaid. Moreover, no money may be set aside for or applied to thepurchase of or redemption (through a sinking fund or otherwise) of any Junior Securities or shares pari passu with the Series A Preferred. Furthermore, the terms of the Debentures provide that at any time when the Debentures remain outstanding, the Company shall not pay cash dividends ordistributions on any equity securities of the Company without the consent of holders of at least 67% in principal amount of the then outstanding Debentures. 37 Restrictions under the Credit Agreement As discussed above, on January 8, 2015 we entered into the Credit Agreement with Heartland Bank. Pursuant to the Credit Agreement, we’re subject tocertain customary working capital restrictions and limitations upon the payment of dividends. For example, we’re prohibited from taking any of thefollowing actions without the prior written consent of Heartland: incurring any debt, other than certain permitted debt as specified in the Credit Agreement;declaring or paying any distributions, including dividends, other than certain permitted distributions specified in the Credit Agreement; making anyacquisitions of the stock or equity interests of another person, other than certain permitted equity acquisitions as specified in the Credit Agreement; ormaking any direct or indirect purchase or other acquisition of stock or other securities of any other person or any other item which would be classified as an“investment” on a balance sheet of such other person, other than certain permitted investments as specified in the Credit Agreement. The foregoingdescription does not purport to be complete and is qualified in its entirety by reference to the full text of the Credit Agreement, a copy of which is filed asExhibit 10.1 to our Current Report on Form 8-K, filed on January 13, 2015. In addition, the terms of some of our outstanding warrants prohibit or restrict the payment of dividends. Recent Sales of Unregistered Securities We have previously disclosed by way of quarterly reports on Form 10-Q and current reports on Form 8-K filed with the SEC all sales by us of our unregisteredsecurities during 2014. Item 6.SELECTED FINANCIAL DATA Not applicable. Item 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with our financial statements included in Part IV of this annual report. This discussion containsforward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-lookingstatements as a result of various factors including those set forth under Part I “Item 1A. Risk Factors.” General Lilis Energy, Inc. (NASDAQ: LLEX) (“we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is a Denver-based upstream independent oil and gascompany engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. We were incorporated in August of 2007 in theState of Nevada as Universal Holdings, Inc. In October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name toLilis Energy, Inc. Our current operating activities are focused on the Denver-Julesburg Basin (“DJ Basin”) in Colorado, Wyoming and Nebraska. Our business strategy isdesigned to maximize shareholder value by leveraging the knowledge, expertise and experience of our management team and via the future exploration anddevelopment of the approximately 65,000 net acres of developed and undeveloped acreage that are currently held by us, primarily in the northern DJ Basin. Overview of 2014 and Recent Developments January 2014 Private Placement On January 22, 2014, we entered into and closed a series of subscription agreements with accredited investors in a private placement transaction, pursuant towhich we issued an aggregate of 2,959,125 units, with each unit consisting of (i) one share of our common stock, par value $0.0001 (the “Common Stock”)and (ii) one three-year warrant to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (together, the “Units”), for a purchaseprice of $2.00 per Unit, for aggregate gross proceeds of $5.92 million (the “January Private Placement”). In conjunction with the January Private Placement,certain of our current and former officers and directors agreed to purchase an additional $1.425 million of Units subject to receipt of shareholder approval asrequired by NASDAQ’s continued listing requirements. However, due to attrition of certain parties who entered into those commitments, we do not expect tocollect on the full amount. The warrants issued in the private placement were not exercisable for six months following the closing of the January PrivatePlacement. 38 May 2014 Private Placement On May 30, 2014, we closed a private placement (the “May Private Placement”) of our Series A 8% Convertible Preferred Stock (“Preferred Stock”) withaccredited investors, pursuant to which we issued $7.50 million of Preferred Stock. The Preferred Stock provides for a dividend of 8% per annum, payablequarterly in arrears, which can be paid in cash or in shares of Common Stock if certain conditions are met. Each investor in the Preferred Stock was alsogranted a three-year warrant to purchase Common Stock equal to 50% of the number of shares that would be issuable upon full conversion of the PreferredStock at the initial conversion price of $2.89. We have the right to convert the Preferred Stock to Common Stock if the Common Stock is traded at $7.50 pershare for ten consecutive trading days and the underlying shares of Common Stock are registered for resale. T.R. Winston & Company, LLC (“TR Winston”)was the placement agent for the transaction and was paid a fee equal to 8% of the proceeds plus an additional 1% of the proceeds plus $25,000 in expenses.Of the $600,000 fee, the placement agent paid $94,150 in commissions to selected dealers and invested $454,000, or 76%, in the May Private Placement forits own account. The Company used $5.0 million of the proceeds of the May Private Placement to make the first cash payment in connection with theHexagon settlement (discussed below), and used the remaining proceeds to fund its oil and gas development projects and for general administrative expenses. On June 6, 2014, TR Winston executed a commitment to purchase or affect the purchase by third parties of an additional $15 million in Preferred Stock, to beconsummated within ninety days thereof. The agreement was subsequently extended and expired on February 22, 2015. On February 25, 2015, the Companyand TR Winston agreed in principal to a replacement commitment, pursuant to which TR Winston has agreed to purchase or affect the purchase by thirdparties of an additional $7.5 million in Preferred Stock, to be consummated no later than February 23, 2016, with all other terms substantially the same asthose of the original commitment. Debenture Conversion and Extension On January 31, 2014, we entered into a Debenture Conversion Agreement (the “Conversion Agreement”), with all of the holders of our 8% Senior SecuredConvertible Debentures (the “Debentures”). Under the terms of the Conversion Agreement, $9.0 million of the approximately $15.6 million in Debenturesthen outstanding immediately converted to Common Stock at a price of $2.00 per share of Common Stock. The balance of the Debentures may be convertedto Common Stock at the election of its holders, subject to receipt of shareholder approval as required by the NASDAQ continued listing requirements. Asadditional inducement for the conversions, we issued to the converting Debenture holders warrants to purchase one share of Common Stock, at an exerciseprice equal to $2.50 per share, for each share of Common Stock issued upon conversion of the Debentures. At December 31, 2014, we had $6.84 million, net, outstanding under our Debentures. The Debentures (as previously amended) were to mature on January 15,2015; however, in connection with our entry into the Credit Agreement (discussed below) in January 2015, as of the date of the report, we have entered intoan extension agreement with the holders of the Debentures, which extends the maturity date until January 8, 2018. The maturity date now coincides with thematurity date of the Credit Agreement (discussed below). Hexagon Settlement On September 2, 2014, we entered into an agreement with Hexagon, LLC (the “Final Settlement Agreement”) to settle all amounts payable by us pursuant toexisting credit agreements with Hexagon, LLC (“Hexagon”) that were secured by mortgages against several of our oil and gas properties (the “HexagonCollateral”). Pursuant to the Final Settlement Agreement, in exchange for full extinguishment of all amounts payable ($15.1 million in principal and interest)pursuant to the credit agreements and related promissory notes, we agreed to assign to Hexagon all of the Hexagon Collateral, and issued to Hexagon $2.0million in a new series of 6% Redeemable Preferred Stock. The Final Settlement Agreement also prohibits Hexagon from selling or otherwise disposing ofany shares of Common Stock held by Hexagon until February 29, 2016. In addition, pursuant to the Final Settlement Agreement, Hexagon and us eachmutually released and discharged all known and unknown claims against the other and their respective representatives that they had or may have, includingclaims relating to the credit agreements. 39 Heartland Bank Credit Agreement On January 8, 2015, we entered into a credit agreement with Heartland Bank (the “Credit Agreement”) which provides for a three-year senior secured termloan in an initial aggregate principal amount of $3.0 million, which principal amount may be increased to a maximum principal amount of $50.0 million atthe request of us, subject to certain conditions, pursuant to an accordion advance provision in the Credit Agreement. The availability of additional funds issubject to the discretion of the lenders, and is generally based on the value of our proved developed producing (“PDP”) and proved undeveloped (“PUD”)reserves. We intend to use proceeds borrowed under the Credit Agreement to fund producing property acquisitions in North America, drill wells in the core ofour lease positions and to fund working capital. Some of the proceeds from the initial borrowing under the Heartland Bank loan were applied to the paymentand servicing of our term debt and working capital and participating in working interests in the Wattenberg area. Financial Condition and Liquidity Information about our year-end financial position is presented in the following table (in thousands): Year ended December 31, 2014 2013 (Restated) Financial Position Summary Cash and cash equivalents $510 $165 Working capital (deficit) $(6,560) $(12,696)Balance outstanding on convertible debentures payable and term loan $6,840 $33,499 Shareholders’ equity $14,067 $5,924 As of December 31, 2014, we had a negative working capital balance and a cash balance of approximately $6.56 million and $510,000, respectively. Also asof December 31, 2014, we had $6.84 million, net, outstanding under the Debentures. The Debentures (as previously amended) were to mature on January 15,2015; however, in connection with our entry into the Credit Agreement in January 2015 the Company has entered into an extension agreement with each ofthe Debenture holders, which extends the maturity date until January 8, 2018. The maturity date now coincides with the maturity date of the CreditAgreement and the Debentures were classified as a long-term liability as of December 31, 2014. Additionally, we had $5.73 million of accrued drillingactivity that is currently in dispute. The Company will either pay the accrued costs and start receiving associated oil and gas revenue or not owe thisobligation. We will require additional capital to satisfy our obligations, to fund our current/future drilling commitments, as well as our acquisition and capital budgetplans; to help fund our ongoing overhead; and to provide additional capital to generally improve our negative working capital position. We anticipate thatsuch additional funding will be provided by a combination of capital raising activities, including borrowing transactions, the sale of additional debt and/orequity securities, and the sale of certain assets and by the development of certain of our undeveloped properties via arrangements with joint venture partners.If we’re not successful in obtaining sufficient cash to fund the aforementioned capital requirements, we will be required to curtail our expenditures, and maybe required to restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, includingdeferring all or portions of our capital budget. There is no assurance that any such funding will be available to us on acceptable terms, if at all. Cash Flows Cash used in operating activities during the year ended December 31, 2014 was $7.31 million. Cash used in operating activities coupled with the $507,000used in investing activities offset by the $8.16 million provided by financing activities, resulted in an increase in cash of $344,000 during the year. 40 The following table compares cash flow items during the year ended December 31, 2014 to December 31, 2013 (in thousands): Year ended December 31, 2014 2013 (Restated) Cash provided by (used in): Operating activities $(7,306) $(1,218)Investing activities (507) (1,204)Financing activities 8,157 1,617 Net change in cash $344 $(805) During the year ended December 31, 2014, net cash used in operating activities was $7.31 million, compared to $1.22 million during the year endedDecember 31, 2013, an increase of cash used in operating activities of $6.09 million, or 499%. The primary changes in operating cash during the year endedDecember 31, 2014 was from a reduction of oil and gas revenues and operating fees of $1.67 million which was offset by a decrease in operating expenses of$257,000 for a net decrease in operating income of $1.41 million, $1.00 million in placement fees paid to TR Winston which was ultimately paid to Mr.Mirman. Additionally, we had increased salaries of $475,000, paid $343,000 for the due diligence of a potential acquisition which did not take place,$250,000 for additional investment banking firms, $650,000 in additional legal fees and approximately $670,000 of other professional fees for acquisitionsand additional support during the year. During the year ended December 31, 2014, net cash used in investing activities was $507,000, compared to net cash used in investing activity of $1.2 millionduring the year ended December 31, 2013, a decrease of cash used in investing activities of $693,000, or 58%. During 2014, we invested $305,000 to obtaincertain undeveloped leases and $190,000 on well development and equipment. During 2013, we invested $1.40 million of cost associated with acquisition ofundeveloped leaseholds and development of assets throughout Wattenberg and the Silo field offset by an increase in cash of $640,000 related to our sale ofoil and gas properties. During the year ended December 31, 2014, net cash provided by financing activities was $8.16 million, compared to net cash provided by financingactivities of $1.62 million during the year ended December 31, 2013, an increase of $6.54 million, or 403%. In 2014, we received cash proceeds from twoprivate placements. We issued common stock and warrants in January 2014 for $5.24 million and issued Series A Preferred Stock in May 2014 for $6.79million, offset by cash repayment of debt of $3.71 million, and a payment of dividends of 162,000. In 2013, we issued additional convertible debt of $2.18million offset by cash repayment of debt of $562,000. Capital Resources and Budget We anticipate a capital budget of up to $50.0 million for 2015. The budget is allocated toward the acquisition of properties and companies in North Americaand to develop two wells focused on unconventional reservoirs located in the Wattenberg field within the DJ Basin that will apply horizontal drilling in theNiobrara shale and Codell formations. The entire capital budget is subject to the securing additional capital through equity placement, utilizing the Credit Agreement from Heartland Bank andadditional debt instruments and funds contemplated by the Credit Agreement to acquire production in North America. Some of the proceeds from the initialborrowing under the Credit Agreement were applied to the payment and servicing of our term debt and working capital and participating in working interestsin the Wattenberg area. In addition to the need to secure adequate capital to fund our capital budget, the execution of, and results from, our capital budget are contingent on variousfactors, including, but not limited to, the sourcing of capital, market conditions, oilfield services and equipment availability, commodity prices and drilling/production results. Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget. Other factors that couldimpact our level of activity and capital expenditure budget include, but are not limited to, a reduction or increase in service and material costs, the formationof joint ventures with other exploration and production companies, and the divestiture of non-strategic assets. 41 As of December 31, 2014 and December 31, 2013, we had $6.04 million and $1.15 million of wells in progress, respectively. Wells in progress are related tocertain wells in our core development program within the Northern Wattenberg field. We capitalized and accrued approximately $5.73 million of coststhrough December 31, 2014 associated with these wells, which are currently in dispute. The dispute relates to our ownership in certain wells being reduced and or eliminated from a possible farm-out. The operator of the producing wells claimswe entered into a farm-out which will reduce our ownership in the wells. Per the terms of the JOA, if we do not generate enough capital from equity or debtraises, then we may be placed in non-pay status with the operator per a Notice of Default. Should this occur, after thirty days without cure, the operator mayforward us a Notice of Non-Consent and a penalty of up to 300% may be imposed in order to buy-back working interest in the newly drilled wells. On March 6, 2015, we filed a lawsuit against the operator. In our complaint, we seek monetary damages and declaratory relief on claims of breach of contract,breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjust enrichment,conversion and declaratory judgment related to the JOA between us and the operator for tortious actions against us. Results of Operations Year ended December 31, 2014 compared to the year ended December 31, 2013 The following table compares operating data for the fiscal year ended December 31, 2014 to December 31, 2013: Year Ended December 31, 2014 2013 (Restated) Revenue: Oil sales $2,581,689 $4,312,325 Gas sales 364,732 340,609 Operating fees 182,773 148,474 Realized gain (loss) on commodity price derivatives 11,143 (17,572)Unrealized gain on commodity price derivatives - 2,475 Total revenues 3,140,337 4,786,311 Costs and expenses: Production costs 954,347 1,217,853 Production taxes 269,823 263,437 General and administrative 10,325,842 4,965,279 Depreciation, depletion and amortization 1,337,662 2,388,871 Total costs and expenses 12,887,675 8,835,440 Loss from operations before conveyance (9,747,338) (4,049,129)Loss on conveyance of oil and gas properties (2,269,760) - Loss from operations (12,017,098) (4,049,129) Other income (expenses): Other income 32,444 11,062 Inducement expense (6,661,275) - Convertible notes conversion derivative gain (loss) (5,526,945) 163,935 Bristol price protection derivative loss 571,228 - Interest expense (4,837,025) (6,136,842)Net Loss $(28,438,671) $(10,010,974) 42 Total revenues Total revenues were $3.14 million for the year ended December 31, 2014, compared to $4.79 million for the year ended December 31, 2013, a decrease of$1.65 million, or 34%. The decrease in revenues was primarily due to the reduction in oil and gas revenue associated with 32,000 acres and 17 operated wellswe conveyed to Hexagon pursuant to the Final Settlement Agreement, discussed above. During the year ended December 31, 2014 and 2013, production amounts were 46,500 and 62,512 BOE, respectively, a decrease of 16,012 BOE, or 26%. Inaddition to the conveyance, production declined due to significant downtime on unsuccessful workovers. The differential between the price per BOEreceived by us and the NYMEX crude price averaged $13.55 for 2014 compared to $7.64 for 2013, an increase of 77% due to the excess supply of oil in thearea. The following table shows a comparison of production volumes and average prices: For the Year Ended December 31, 2014 2013 Product Oil (Bbl.) 33,508 51,705 Oil (Bbls)-average price (1) $77.05 $83.40 Natural Gas (MCF)-volume 77,954 64,845 Natural Gas (MCF)-average price (2) $4.68 $5.25 Barrels of oil equivalent (BOE) 46,500 62,512 Average daily net production (BOE) 127 171 Average Price per BOE (1) $63.36 $74.43 (1)Does not include the realized price effects of hedges(2)Includes proceeds from the sale of NGL's Oil and gas production costs, production taxes, depreciation, depletion, and amortization Production costs per BOE 20.52 19.48 Production taxes per BOE 5.80 4.21 Depreciation, depletion, and amortization per BOE 28.76 38.21 Total operating costs per BOE (1) $55.08 $61.90 Gross margin per BOE (1) $8.28 $12.53 Gross margin percentage 13% 17% (1)Does not include the loss on conveyance Commodity Price Derivative Activities Changes in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivativeinstruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted exclusively of swaps. Theduration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operatingstrategy. As of December 31, 2014, we did not maintain any active commodity swaps. 43 During 2014, we held one commodity swap which matured on January 31, 2014. Commodity price derivative realized gains were $11,000 for the year endedDecember 31, 2014, compared to a realized loss of $18,000 during the year ended December 31, 2013. Commodity price derivative unrealized gains was$2,000 for the year ended December 31, 2013. Production costs Production costs were $954,000 during the year ended December 31, 2014, compared to $1.22 million for the year ended December 31, 2013, a decrease of$266,000, or 22%. Decrease in production costs in 2014 was from a decrease in operated wells related to the Hexagon conveyance of properties describedabove. Production costs per BOE increased to $20.52 for the year ended December 31, 2014 from $19.48 in 2013, an increase of $1.04 per BOE, or 5%,primarily as a result of increased volumes of BOE in 2014 and high well work frequency. During the first nine months of 2014, work-over rigs had limitedavailability due to high industry activity within our operating area and the fact that we performed an in-depth analysis of production and started to reduce theamount of on-time that the wells pumped. As a result, we had idled wells for regular scheduled well maintenance or other repairs. Production taxes Production taxes were $270,000 for the year ended December 31, 2014, compared to $263,000 for the year ended December 31, 2013, an increase of $7,000,or 2%. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from which production isderived. Production taxes per BOE increased to $5.80 during the year ended December 31, 2014 from $4.21 in 2013, an increase of $1.59 or 38%. Theincrease in production tax is a result of the change in product mix by state. We produced more oil and natural gas from higher taxed states and counties in2014 compared to 2013. General and administrative General and administrative expenses were $10.33 million during the year ended December 31, 2014, compared to $4.97 million during the year endedDecember 31, 2013, an increase of $5.36 million, or 108%. Non-cash general and administrative items for the year ended December 31, 2014 were $4.43million compared to $1.73 million during the year ended December 31, 2013, an increase of $2.70 million, or 156%. The increase in non-cash general andadministrative expenses was due to an increase of $686,000 in fees associated with completing the January Private Placement; increased stock basedcompensation of $754,000 for compensation to employees, directors, consultants compared to prior year, $965,000 Bristol warrant liability (described below)and increase in reserve for bad debt of $30,000. Cash general and administrative expenses were $5.90 million during the year ended December 31, 2014,compared to $1.83 million during the year ended December 31, 2013, an increase of $4.07 million, or 222%. The increase in cash general and administrativeexpenses was largely due to a $1.00 million in placement fees paid to TR Winston which was ultimately paid to Mr. Mirman. In connection with theappointment of Mr. Mirman, Chief Executive Officer, the Company and TR Winston amended the investment banking agreement in place between theCompany an TR Winston at that time to provide that, upon the receipt by the Company of gross cash proceeds or drawing availability of at least $30 million,measured on a cumulative basis and including certain restructuring transactions, subject to the Company’s continued employment of Mr. Mirman, TRWinston would receive from the Company a lump sum payment of $1 million. Mr. Mirman’s compensation arrangements with TR Winston provided thatupon TR Winston’s receipt from the Company of the lump sum payment, TR Winston would make a payment of $1 million to Mr. Mirman. The Boarddetermined in September 2014 that the criteria for the lump sum payment had been met. Additionally, the Company had increased salaries of $475,000, paid$343,000 for the due diligence of a potential acquisition which did not take place, $250,000 for additional investment banking firms, $650,000 in additionallegal fees and approximately $670,000 of other professional fees for acquisitions and additional support during the year. Depreciation, depletion, and amortization Depreciation, depletion, and amortization were $1.34 million during the year ended December 31, 2014, compared to $2.39 million during the year endedDecember 31, 2013, a decrease of $1.05 million, or 44%. Decrease in depreciation, depletion, and amortization was from (i) a decrease in production amountsin 2014 from 2013, (ii) an decrease in the depletion base for the depletion calculation due to the conveyance of property, and (iii) a decrease in the depletionrate. During the year ended December 31, 2014 and 2013, production amounts were 46,500 and 62,512 BOE, respectively, a decrease of 16,012 BOE, or26%. Inducement expense In January 2014, the Company incurred an inducement expense of $6.66 million. The Company entered into the Conversion Agreement with all of theholders of our Debentures. Under the terms of the Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures then outstandingconverted to Common Stock at a price of $2.00 per common share. As inducement, the Company issued warrants to the converting Debenture holders topurchase one share of Common Stock, at an exercise price equal to $2.50 per share (the “Warrants”), for each share of Common Stock issued upon conversionof the Debentures. The Company used the Lattice model to value the warrants, utilizing a volatility of 65%, and a life of 3 years and arrived at a fair value of$6.66 million for the Warrants. 44 Loss on conveyance of oil and gas properties On September 2, 2014, we entered into the Final Settlement Agreement to settle all amounts payable by the Company pursuant to existing credit agreementswith Hexagon (described above). The transaction was accounted for under the full cost method of accounting for oil and natural gas operations. Under the fullcost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs,with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil andgas attributable to the cost center. The transfer to Hexagon represents greater than 25 percent of the Company’s proved reserves of oil and gas attributable tothe full cost pool and thus we incurred a loss on the conveyance. Following this methodology, the following table represents an allocation of the transaction. Payment of debt and accrued interest payable $15,063,289 Add: disposition of asset retirement obligations 973,132 Total disposition of liabilities $16,036,421 Proved oil and natural gas properties $32,574,603 Accumulated depletion (22,148,686)Unproved oil and natural gas properties 6,194,162 Redeemable Preferred Stock at fair value 1,686,102 Total conveyance of assets and preferred stock 18,306,181 Loss on conveyance $(2,269,760) Impairment of developed properties During the year ended December 31, 2014 and 2013, the Company did not impair any of its evaluated properties. If commodity prices stay at current early 2015 levels or decline further, we will incur full cost ceiling impairments in future quarters. Because the ceilingcalculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 2015 compared to 2014 is a lower ceilingvalue each quarter. This will result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges would not affect cash flow fromoperating activities, but would adversely affect our net income and stockholders’ equity. Interest Expense For the years ended December 31, 2014 and 2013, the Company incurred interest expense of approximately $4.84 million and $6.14 million, respectively, ofwhich approximately $2.42 million and $1.68 million is classified as non-cash interest expense, respectively. The details of the non-cash interest expense forthe year ended December 31, 2014 are as follows: (i) Hexagon non-payment penalty of $1 million (ii) amortization of the deferred financing costs of$235,000, (iii) accretion of the convertible debentures payable discount of $849,000, (iv) Common Stock issued for interest of $1.19 million, (v) accruedinterest to convertible debenture of $7,000, and (vi) amortization of forbearance fees of $250,000. The details of the non-cash interest expense for the yearended December 31, 2013 are as follows: (i) amortization of the deferred financing costs of $680,000, (ii) accretion of the convertible debentures payablediscount of $2.14 million, (iii) common stock issued for interest of $1.17 million and (iv) accrued interest of convertible debentures of $160,000. Cashinterest for 2014 was $1.09 million compared to $2.09 million in 2013. 45 Change in Bristol warrant liability During 2014, we entered into a consulting agreement with Bristol. As a part of the agreement, we issued 1 million warrants/options with an exercise price of$2.00 a share. The warrant/ option will automatically ratchet down to its new price if we issue securities under another consulting agreement with a lowerexercise price. The change in fair value of this warrant provision was $571,000 for the year ended December 31. 2014. Change in derivative liability of convertible debentures For the years ended December 31, 2014 and 2013, we incurred a change in the fair value of the derivative liability related to the convertible debentures ofapproximately $5.53 million and ($164,000) respectively. During the year ended December 31, 2014, we reduced the conversion price from $4.25 to $2.00,consistent with the January Private Placement. The conversion resulted in a reduction of the convertible debenture liability by $5.69 million and an increasein additional paid in capital. Off-Balance Sheet Arrangements We do not have any off-balance sheet arrangements. Critical Accounting Policies and Estimates The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States, or GAAP, requiresour management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure ofcontingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. Thefollowing is a summary of the significant accounting policies and related estimates that affect our financial disclosures. Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial conditionand results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the timethe estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results ofoperations or financial condition. Use of Estimates The financial statements included herein were prepared from our records in accordance with GAAP, and reflect all normal recurring adjustments which are, inthe opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods. The preparationof the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gasreserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenuesand expenses during the reporting period. We evaluate our estimates on an on-going basis and base our estimates on historical experience and on variousother assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptionsor conditions, we believe that our estimates are reasonable. The preparation of financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reportedamounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts ofrevenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates andassumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Our most significant financial estimates are associated with our estimated proved oil and gas reserves, assessments of impairment imbedded in the carryingvalue of undeveloped acreage and proven properties, as well as the valuation of Common Stock, options and warrants, and estimated derivative liabilities. 46 Oil and Natural Gas Reserves We follow the full cost method of accounting. All of our oil and gas properties are located within the United States, and therefore all costs related to theacquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration anddevelopment costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gasreserves. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes maynot exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cashoutflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, ofunproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the SEC rules, we prepared our oil and gasreserve estimates as of December 31, 2014, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2014. Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies oninterpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. Theprocess also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses,capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; theinterpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate. We believe estimated reserve quantities and the related estimates of future net cash flows are among the most important estimates made by an exploration andproduction company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used asthe basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation andimpairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and naturalgas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs underexisting economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applyingbenchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil andnatural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends uponthe purpose for which the reserve estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discountrate. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those ofestablished proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independentreserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oiland natural gas prices and operating and capital costs change. We evaluate and estimate our oil and natural gas reserves as of December 31 and quarterlythroughout the year. For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact ofacquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows arerecorded in the period in which the reserves or net cash flow estimate changes. Oil and Natural Gas Properties—Full Cost Method of Accounting We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into asingle cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities. Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimatedgross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unitof measure. Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. This undeveloped acreage is assessed quarterly toascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or theamount of the impairment is added to the full cost pool and becomes subject to depletion calculations. 47 Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter therate of depletion by more than 25%. Royalties paid, net of any tax credits received, are netted against oil and natural gas sales. In applying the full cost method, we perform a ceiling test on properties that restricts the capitalized costs, less accumulated depletion, from exceeding anamount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleumengineers. The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the endof the applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financingcosts, future site restoration costs and income taxes. Under the full cost method of accounting, capitalized oil and natural gas property costs, lessaccumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future netrevenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed thisceiling, we would recognize impairment. Revenue Recognition The Company derives revenue primarily from the sale of produced natural gas and crude oil. The Company reports revenue as the gross amount receivedbefore taking into account production taxes and transportation costs, which are reported as separate expenses and are included in oil and gas productionexpense in the accompanying consolidated statements of operations. Revenue is recorded in the month the Company’s production is delivered to thepurchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that titleto the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and theprice the Company will receive. The Company uses its knowledge of its properties, its historical performance, NYMEX and local spot market prices, qualityand transportation differentials, and other factors as the basis for these estimates. Share Based Compensation The Company accounts for share-based compensation by estimating the fair value of share-based payment awards made to employees and directors,including stock options, restricted stock grants, and employee stock purchases related to employee stock purchase plans, on the date of grant using anoption-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite serviceperiods. Derivative Instruments Periodically, the Company entered into swaps to reduce the effect of price changes on a portion of our future oil production. We reflect the fair market valueof our derivative instruments on our balance sheet. Our estimates of fair value are determined by obtaining independent market quotes as well as utilizing avaluation model that is based upon underlying forward curve data and risk free interest rates. Changes in commodity prices will result in substantially similarchanges in the fair value of our commodity derivative agreements. We do not apply hedge accounting to any of our derivative contracts, therefore werecognize mark-to-market gains and losses in earnings currently. Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Not applicable. Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Our financial statements appear immediately after the signature page of this report. See Index to Financial Statements included in this report. 48 Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE On November 7, 2014, we were notified by our independent registered public accounting firm, Hein & Associates LLP (“Hein”) that it did not wish to standfor re-election. On November 25, 2014, the Company engaged Marcum LLP as the Company’s independent registered public accounting firm, which wasapproved by our Board. The reports of Hein on the consolidated financial statements of the Company as of and for the fiscal years ended December 31, 2013and December 31, 2012, did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, oraccounting principles. During the two most recent fiscal years ended December 31, 2013 and December 31, 2012, there were no disagreements between theCompany and Hein on any matter of accounting principles or practices, financial statement disclosures, or auditing scope or procedures, whichdisagreements, if not resolved to the satisfaction of Hein would have caused them to make reference thereto in their reports on the Company’s financialstatements for such years. For more information on the change in accountants, please see our Form 8-Ks filed with the Securities and Exchange Commissionon November 13, 2014 and December 2, 2014. Item 9A.CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures(as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, (the “Exchange Act”)) as of December 31,2014. Disclosure controls and procedures are controls and other procedures designed to ensure that information required to be disclosed by the Company inits reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities andExchange Commission’s rules and forms and include, without limitation, controls and procedures designed to ensure that information that the Company isrequired to disclose in such reports is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer,as appropriate to allow timely decisions regarding required disclosures. Based upon that evaluation, our Chief Executive Officer and our Chief FinancialOfficer concluded that, as of December 31, 2014, the Company’s internal controls and procedures were not effective, due to the material weaknesses ininternal controls over financial reporting described below. Internal Controls over Financial Reporting Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f)under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements in accordance with GAAP. Because of its inherent limitations, internal control over financial reportingmay not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may becomeinadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on the evaluation and the identification of the material weakness in internal control over financial reporting described below, our Chief ExecutiveOfficer and our Chief Financial Officer have concluded that, as of December 31, 2014, the Company’s internal controls and procedures were not effective. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatementof the annual or interim financial statements will not be prevented or detected. In connection with management’s assessment of our internal control overfinancial reporting, conducted based on the Internal Control—Integrated Framework issued by COSO (1992), we identified the following materialweaknesses in our internal control over financial reporting as of December 31, 2014: ●As a result of the resignation of our Chief Financial Officer as previously disclosed by way of current reports on Form 8-K, we did not maintaineffective monitoring controls and related segregation of duties over automated and manual journal entry transaction processes. ●As disclosed in our Form 8-K filed on November 13, 2014, the Company determined that during the fourth quarter of 2013 and the first threequarters of 2014, there existed a material weakness with respect to the operation of the Company’s internal controls relating to the documentationand authorization procedures of certain travel and entertaining expenses incurred by certain past and present officers in those periods. 49 Restatement of Previously Issued Financial Statements As discussed below in Note 3—Summary of Significant Accounting Policies and Estimates— Restatement and Reclassification, in February 2015, theCompany discovered an error in the valuation of the conversion derivative liability of the Company’s Debentures for the periods ended December 31, 2011,December 31, 2012, December 31, 2013, March 31, 2014 and June 30, 2014 (together, the “Relevant Periods”). Specifically, the calculation of theconversion liability included in the Company’s financial statements for the Relevant Periods only included the value of the price protection (anti-dilution)feature, when it should have included both the conversion option and the price protection embedded in the Debentures. The changes in the value of thederivative resulted in changes to the Company’s financial statements, which warranted restatement of the Company’s Quarterly Reports on Form 10-Q for thefiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014. As a result of the restatement described herein, the Company’s Chief Executive Officer and Chief Financial Officer, with the assistance of other members ofmanagement and expert internal control consultants, re-evaluated the effectiveness of the Company’s internal controls over financial reporting as ofDecember 31, 2014 in accordance with the assessment and testing procedures described above. Based on this re-evaluation, and because the impact of theerrors on the Company’s quarterly financial statements for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014, described inNote 3—Summary of Significant Accounting Policies and Estimates— Restatement, was sufficiently material to warrant restatement of the Company’squarterly reports on Form 10-Q for those periods, we have determined that the following additional material weakness in internal controls over financialreporting existed as of December 31, 2014: ●We did not maintain effective controls to provide reasonable assurance that our convertible debenture conversion derivative liability was beingvalued correctly during the fiscal years ended December 31, 2011, December 31, 2012 and December 31, 2013 and the quarters ended March 31,2014 and June 30, 2014. This material weakness resulted in errors in our financial statements and related disclosures, including inaccuracies inpreviously reported fair value of convertible debentures debenture derivative liability, convertible debenture discount, net gain/loss and totalshareholders’ equity. Because of the material weaknesses described above, management has concluded that we did not maintain effective internal control over financial reportingas of December 31, 2014, based on the Internal Control—Integrated Framework issued by COSO (1992). Remediation Efforts We plan to make necessary changes and improvements to the overall design of our control environment to address the material weaknesses in internal controlover financial reporting described above. In particular, we have hired and expect to hire additional employees to assist with strengthening the segregation ofduties and control activities in journal entry processing and complex accounting issues such as those related to our convertible debentures. We also expect tohire an external expert to help with the valuation of convertible debentures. Additionally, we have begun to perform an analysis of all automated and manualprocedures to strengthen the effectiveness of our segregation of duties and control environment. At any time, if it appears any control can be implemented tomitigate risks, it is immediately implemented. In the fourth quarter of 2014, we implemented a new extensive Travel and Expense policy which all employees and directors are required to review and sign.Furthermore, the Company has required all employees and directors to review and sign all of the Company’s corporate documents which include, but are notlimited to, the Code of Ethics, By-laws, and Corporate Governance Policy. The Company is planning to test the remediation in second quarter of 2015 andfully remediate the weakness by that time. In March 2015, we appointed Kevin Nanke Chief Financial Officer. Mr. Nanke will bring additional oversight in financial reporting and strengthen thesegregation of duties. Management believes through their appointment of a new Chief Financial Officer and the implementation of the foregoing policies, they will significantlyimprove our control environment, the completeness and accuracy of underlying accounting data and the timeliness with which we are able to close ourbooks. Management is committed to continuing efforts aimed at fully achieving an operationally effective control environment and timely filing ofregulatory required financial information. The remediation efforts noted above are subject to our internal control assessment, testing, and evaluationprocesses. While these efforts continue, we will rely on additional substantive procedures and other measures as needed to assist us with meeting theobjectives otherwise fulfilled by an effective control environment. Changes in Internal Control over Financial Reporting Other than those described above, management has determined that there were no changes in the Company’s internal controls over financial reporting duringthe fourth quarter of the year ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internalcontrol over financial reporting. Item 9B.OTHER INFORMATION None. 50 PART III Item 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2015 annual shareholders meeting and isincorporated by reference in this report. Item 11.EXECUTIVE COMPENSATION Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2015 annual shareholders meeting and isincorporated by reference in this report. Item 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2015 annual shareholders meeting and isincorporated by reference in this report. Item 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2015 annual shareholders meeting and isincorporated by reference in this report. Item 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2015 annual shareholders meeting and isincorporated by reference in this report. 51 PART IV Item 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES INDEX TO FINANCIAL STATEMENTS a) Reports of Independent Registered Public Accounting FirmsF-1 and F-2Balance Sheet as of December 31, 2014 and Restated Balance Sheet as of December 31, 2013F-3 and F-4Statement of Operations for the year ended December 31, 2014 and Restated Statement of Operations for the year ended December 31, 2013F-5Statement of Stockholders’ Equity for the years ended December 31, 2014 and 2013.F-6Statement of Cash Flows for the year ended December 31, 2014 and Restated Statement of Cash Flows for the year ended 2013F-7Notes to Financial StatementsF-8 b) Financial statement schedules Not applicable. c) Exhibits The information required by this Item is set forth on the exhibit index that follows the signature page to this Annual Report on Form 10-K. 52 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized. LILIS ENERGY, INC. Date: April 15, 2015By:/s/ Abraham Mirman Abraham Mirman Chief Executive Officer(Authorized Signatory) Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of theregistrant in the capacities and on the dates indicated. Signature Title Date /s/ Abraham Mirman Chief Executive Officer, Director April 15, 2015Abraham Mirman (Principal Executive Officer) /s/ Kevin K. Nanke Executive Vice President and Chief Financial Officer April 15, 2015Kevin Nanke (Principal Financial Officer) /s/ Eric Ulwelling Principal Accounting Officer and Controller April 15, 2015Eric Ulwelling /s/ Nuno Brandolini Chairman of the Board April 15, 2015Nuno Brandolini /s/ General Merrill McPeak Director April 15, 2015General Merrill McPeak /s/ Ronald D. Ormand Director April 15, 2015Ronald D. Ormand /s/ G. Tyler Runnels Director April 15, 2015G. Tyler Runnels 53 Exhibit Index The following exhibits are either filed herewith or incorporated herein by reference: 3.1Amended and Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 from the Company’s current report on Form 8-Kfiled on October 20, 2011).3.2Certificate of Amendment to the Articles of Incorporation of Recovery Energy, Inc. (incorporated herein by reference to Exhibit 3.1 from theCompany’s current report on Form 8-K filed on November 19, 2013).3.3Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s current report on Form 8-K filed on June 18,2010).3.4Certificate of Designation of Preferences, Rights, and Limitations, dated May 30, 2014 (incorporated herein by reference to Exhibit 3.1 from theCompany’s current report on Form 8-K filed on June 4, 2014).3.5Amendment to Certificate of Designations of Preferences, Rights, and Limitations, dated June 12, 2014 (incorporated herein by reference toExhibit 3.1 from the Company’s quarterly report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014).3.6Certificate of Designation of 6% Redeemable Preferred Stock, dated August 29, 2014 (incorporated by reference to Exhibit 3.3 to the Company’squarterly report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).4.1Form of Warrant Issued in Private Placement (incorporated herein by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filedon June 4, 2010).4.2Warrant to Purchase Common Stock of Recovery Energy, Inc. issued to Hexagon Investments, LLC dated May 28, 2010 (incorporated herein byreference to Exhibit 4.2 to the Company’s current report on Form 8-K filed on June 4, 2010).4.3Five Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company’s currentreport on Form 8-K filed on June 18, 2010).4.4Form of $2.20 Warrant Issued to Persons Exercising $1.50 Warrants (incorporated herein by reference to Exhibit 4.1 to the Company’s currentreport on Form 8-K filed on October 8, 2010).4.5Warrant Issued to Hexagon Investments, LLC on January 1, 2011 (incorporated herein by reference to Exhibit 4.1 to the Company’s currentreport on Form 8-K filed on January 4, 2011).4.6Form of Warrant (incorporated by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on January 28, 2014).4.7Form of Warrant (incorporated by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on February 6, 2014).4.8Five Year Warrant to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.1 to the Company’s quarterly reporton Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).4.9Five Year Warrant (Anniversary Warrant) to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.2 to theCompany’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).4.10Form of Warrant dated May 30, 2014 (incorporated herein by reference to Exhibit 10.2 from the Company’s current report on Form 8-K filed onJune 4, 2014).4.11Warrant to Purchase Common Stock issued to Bristol Capital (incorporated herein by reference to Exhibit 4.3 to the Company’s quarterly reporton Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).4.12Warrant to Purchase Common Stock issued to Heartland Bank (incorporated herein by reference to Exhibit 4.3 to the Company’s quarterly reporton Form 10-Q, filed on February 26, 2015).10.1Credit Agreement with Hexagon Investments, LLC dated effective as of January 29, 2010 (incorporated herein by reference to Exhibit 10.12 tothe Company’s current report on Form 8-K filed on March 4, 2010).10.2Promissory Note for financing with Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.13to the Company’s current report on Form 8-K filed on March 4, 2010).10.3Nebraska Mortgage to Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.14 to theCompany’s current report on Form 8-K filed on March 4, 2010).10.4Colorado Mortgage to Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.15 to theCompany’s current report on Form 8-K filed on March 4, 2010). 54 10.5Credit Agreement with Hexagon Investments, LLC dated effective as of March 25, 2010 (incorporated herein by reference to Exhibit 10.17 to theCompany’s current report on Form 8-K filed on March 25, 2010).10.6Promissory Note for financing with Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.18 tothe Company’s current report on Form 8-K filed on March 25, 2010).10.7Nebraska Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.19 to theCompany’s current report on Form 8-K filed on March 25, 2010).10.8Wyoming Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.20 to theCompany’s current report on Form 8-K filed on March 25, 2010).10.9Credit Agreement with Hexagon Investments, LLC dated as of April 14, 2010 (incorporated herein by reference to Exhibit 10.2 to theCompany’s current report on Form 8-K filed on April 20, 2010).10.10Promissory Note with Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company’scurrent report on Form 8-K filed on April 20, 2010).10.11Letter Agreement with Hexagon Investments, LLC (incorporated herein by reference to Exhibit 10.4 to the Company’s current report on Form 8-K filed on June 4, 2010).10.12Wyoming Mortgage to Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.5 to the Company’scurrent report on Form 8-K filed on April 20, 2010).10.13Registration Rights Agreement with Hexagon Investments, Inc. (incorporated herein by reference to Exhibit 10.5 to the Company’s currentreport on Form 8-K filed on June 18, 2010).10.14Stockholders Agreement with Hexagon Investments Incorporated (incorporated herein by reference to Exhibit 10.1 to the Company’s currentreport on Form 8-K filed on June 29, 2010).10.15Amendments to Hexagon Investments, LLC Promissory Notes dated December 29, 2010 (incorporated herein by reference to Exhibit 10.2 to theCompany’s current report on Form 8-K filed on January 4, 2011).10.16Amendments to three Credit Agreements with Hexagon, LLC, dated March 15, 2012 (incorporated herein by reference to Exhibit 10.55 to theCompany’s annual report on Form 10-K for the period ended December 31, 2011, filed on March 21, 2012).10.17Second Amendments to three Credit Agreements with Hexagon, LLC, dated July 31, 2012 (incorporated herein by reference to Exhibit 10.1 tothe Company’s current report on Form 8-K filed on August 2, 2012).10.18Third Amendment to Credit Agreement (First Credit Agreement), dated November 8, 2012 (incorporated herein by reference to Exhibit 10.18 tothe Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.19Third Amendment to Credit Agreement (Second Credit Agreement), dated November 8, 2012 (incorporated herein by reference to Exhibit 10.19to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.20Third Amendment to Credit Agreement (Third Credit Agreement), dated November 8, 2012 (incorporated herein by reference to Exhibit 10.20 tothe Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.21Fourth Amendment to Credit Agreement (First Credit Agreement), dated April 15, 2013 (incorporated herein by reference to Exhibit 10.57 to theCompany’s annual report on Form 10-K for the year ended December 31, 2012, filed on April 17, 2013).10.22Fourth Amendment to Credit Agreement (Second Credit Agreement), dated April 15, 2013 (incorporated herein by reference to Exhibit 10.58 tothe Company’s annual report on Form 10-K for the year ended December 31, 2012, filed on April 17, 2013).10.23Fourth Amendment to Credit Agreement (Third Credit Agreement), dated April 15, 2013 (incorporated herein by reference to Exhibit 10.59 tothe Company’s annual report on Form 10-K for the year ended December 31, 2012, filed on April 17, 2013).10.24First Amendment to Nebraska Mortgage to Hexagon, LLC, dated March 1, 2013 (incorporated herein by reference to Exhibit 10.24 to theCompany’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014). 55 10.25Wyoming Mortgage to Hexagon, LLC, dated March 1, 2013 (incorporated herein by reference to Exhibit 10.25 to the Company’s annual reporton Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.26Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed onJune 4, 2010).10.27Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed onJune 4, 2010).10.28Form of Convertible Debenture Securities Purchase Agreement dated February 2, 2011 (incorporated herein by reference to Exhibit 10.1 to theCompany’s current report on Form 8-K filed on February 3, 2011). 10.29Form of Convertible Debenture (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on February3, 2011).10.30Amendment to 8% Senior Secured Convertible Debentures dated December 16, 2011 (incorporated herein by reference to Exhibit 10.1 to theCompany’s current report on Form 8-K filed on December 19, 2011).10.31Second Amendment to 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.56 tothe Company’s annual report on Form 10-K for the year ended December 31, 2011, filed on March 21, 2012).10.32Securities Purchase Agreement for additional 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein byreference to Exhibit 10.57 to the Company’s annual report on Form 10-K for the year ended December 31, 2011, filed on March 21, 2012).10.33Form of 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.58 to the Company’sannual report on Form 10-K for the year ended December 31, 2011, filed on March 21, 2012).10.34Amendment to 8% Senior Secured Convertible Debenture and Waiver under Securities Purchase Agreement, dated July 23, 2012 (incorporatedherein by reference to Exhibit 10.35 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11,2014).10.35Amendment to Securities Purchase Agreement dated August 7, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s currentreport on Form 8-K filed on August 9, 2012).10.36Amendment to Securities Purchase Agreement dated August 7, 2012 (incorporated herein by reference to Exhibit 10.2 to the Company’s currentreport on Form 8-K filed on August 9, 2012).10.37Amendment to 8% Senior Secured Convertible Debentures due February 8, 2014, dated April 15, 2013 (incorporated herein by reference toExhibit 10.56 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.38Letter Agreement with Debenture Holder dated April 16, 2013 (incorporated herein by reference to Exhibit 10.39 to the Company’s annualreport on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.39Securities Purchase Agreement dated June 18, 2013 (incorporated herein by reference to Exhibit 10.1 to the Company’s quarterly report on Form10-Q for the quarter ended June 30, 2013, filed on August 15, 2013).10.40Form of Convertible Debenture (incorporated herein by reference to Exhibit 10.2 to the Company’s quarterly report on Form 10-Q for the quarterended June 30, 2013, filed on August 15, 2013).10.41Letter Agreement dated June 18, 2013 regarding 8% Senior Secured Debentures (incorporated herein by reference to Exhibit 10.3 to theCompany’s quarterly report on Form 10-Q for the quarter ended June 30, 2013, filed on August 15, 2013).10.42Letter of Intent with Shoreline Energy Corp., dated February 4, 2014 (incorporated herein by reference to Exhibit 10.44 to the Company’s annualreport on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.43Debenture Conversion Agreement, dated as of January 31, 2014 (incorporated herein by reference to Exhibit 10.1 from the Company’s currentreport on Form 8-K filed on February 6, 2014).10.44Form of Subscription Agreement, dated January 22, 2014 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report onForm 8-K filed on January 28, 2014.10.45Form of Hexagon Replacement Note (incorporated herein by reference to Exhibit 10.4 from the Company’s current report on Form 8-K filed onJune 4, 2014).10.46Letter Agreement dated May 19, 2014 with holders of the 8% Senior Secured Convertible Debentures (incorporated herein by reference toExhibit 10.1 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014). 56 10.47Amendment to Debentures dated June 6, 2014 (incorporated herein by reference to Exhibit 10.2 to the Company’s quarterly report on Form 10-Qfor the period ended March 31, 2014, filed on June 17, 2014).10.48Termination of Investment Banking Agreement with T.R. Winston dated as of March 19, 2013 (incorporated herein by reference to Exhibit 10.5to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.49Transaction Fee Agreement with T.R. Winston dated as of March 28, 2014 (incorporated herein by reference to Exhibit 10.6 to the Company’squarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.50Amendment to Transaction Fee Agreement with T.R. Winston dated as of April 29, 2014 (incorporated herein by reference to Exhibit 10.7 to theCompany’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.51Engagement Agreement for Financial Advisory Services with MLV & Co. LLC dated as of February 21, 2014 (incorporated herein by referenceto Exhibit 10.8 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.52†Consulting Agreement with Market Development Consulting Group, Inc. dated January 17, 2014 (incorporated herein by reference to Exhibit10.28 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.53†Market Development Consulting Group, Inc. Termination letter, dated August 1, 2014 (incorporated herein by reference to Exhibit 10.15 to theCompany’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).10.54†Consulting Agreement with Bristol Capital dated September 2, 2014 (incorporated herein by reference to Exhibit 10.11 to the Company’squarterly report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).10.55Form of Securities Purchase Agreement dated May 30, 2014 (incorporated herein by reference to Exhibit 10.1 from the Company’s current reporton Form 8-K filed on June 4, 2014).10.56Hexagon Settlement Agreement, dated May 30, 2014 (incorporated herein by reference to Exhibit 10.3 from the Company’s current report onForm 8-K filed on June 4, 2014).10.57Settlement Agreement with Hexagon dated September 2, 2014 (incorporated herein by reference to Exhibit 10.10 to the Company’s quarterlyreport on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).10.58Letter Agreement with holders of the Company’s 8% Senior Secured Convertible Debentures, dated October 6, 2014 (incorporated herein byreference to Exhibit 99.1 from the Company’s current report on Form 8-K filed on October 7, 2014).10.59Credit Agreement, dated January 8, 2015, among Lilis Energy, Inc., Heartland Bank, as administrative agent, and the other lender parties thereto(incorporated herein by reference to Exhibit 10.1 from the Company’s current report on Form 8-K filed on January 13, 2015).10.60Security Agreement, dated as of January 8, 2015, by and between Lilis Energy, Inc. and Heartland Bank, as collateral agent (incorporated hereinby reference to Exhibit 10.12(a) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February26, 2015).10.61Form of Promissory Note from Lilis Energy, Inc. as Borrower to Heartland Bank as Payee, dated as of January 8, 2015 (incorporated herein byreference to Exhibit 10.12(b) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26,2015).10.62Subordination Agreement, dated as of January 8, 2015 (incorporated herein by reference to Exhibit 10.12(c) from the Company’s quarterly reporton Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).10.63Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Colorado Oil and Gas Properties) (incorporated hereinby reference to Exhibit 10.12(d) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February26, 2015).10.64Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Nebraska Oil and Gas Properties) (incorporated hereinby reference to Exhibit 10.12(e) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February26, 2015).10.65Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Wyoming Oil and Gas Properties) (incorporated hereinby reference to Exhibit 10.12(f) from the Company’s quarterly report on Form 10-Q for the quarter ended September 30, 2014, filed on February26, 2015). 57 10.66Letter Agreement with holders of the Company’s 8% Senior Secured Convertible Debentures (incorporated herein by reference to Exhibit 10.13to the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).10.67†Recovery Energy, Inc. 2012 Equity Incentive Plan dated August 31, 2012, as amended on November 13, 2013 (incorporated by reference toExhibit 10.1 to the Company’s current report on Form 8-K filed on November 19, 2013).10.68†Employment Agreement between the Company and A. Bradley Gabbard (incorporated herein by reference to Exhibit 10.4 to the Company’squarterly report on Form 10-Q for the quarter ended June 30, 2013, filed on August 15, 2013)10.69†Stock Option Award Agreement with A. Bradley Gabbard dated as of June 25, 2013 (incorporated herein by reference to Exhibit 10.58 to theCompany’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.70†Stock Option Award Agreement with W. Phillip Marcum dated as of June 25, 2013 (incorporated herein by reference to Exhibit 10.59 to theCompany’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.71†Employment Agreement between the Company and W. Phillip Marcum (incorporated herein by reference to Exhibit 10.5 to the Company’squarterly report on Form 10-Q for the quarter ended June 30, 2013, filed on August 15, 2013).10.72†Separation Agreement with W. Phillip Marcum dated April 24, 2014 (incorporated herein by reference to Exhibit 10.3 to the Company’squarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.73†Employment Agreement with Robert A. Bell dated May 1, 2014 (incorporated herein by reference to Exhibit 10.4 to the Company’s quarterlyreport on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).10.74†Independent Director Appointment Agreement with Robert A. Bell effective March 1, 2014 (incorporated herein by reference to Exhibit 10.55 tothe Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.75†Separation Agreement with Robert A. Bell dated August 1, 2014 (incorporated herein by reference to Exhibit 10.9 to the Company’s quarterlyreport on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).10.76†Independent Director Appointment Agreement with Nuno Brandolini effective March 1, 2014 (incorporated herein by reference to Exhibit 10.55to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).10.77†Option Award Agreement between the Company and Nuno Brandolini, dated as of October 1, 2014 (fully-vested) (incorporated herein byreference to Exhibit 10.5 to the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).10.78†Option Award Agreement between the Company and Nuno Brandolini, dated as of October 1, 2014 (subject to vesting) (incorporated herein byreference to Exhibit 10.6 to the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).10.79†Lilis Energy, Inc. Director Agreement with G. Tyler Runnels (incorporated herein by reference to Exhibit 10.1 from the Company’s current reporton Form 8-K filed on December 2, 2014).10.80†Employment Agreement with Eric Ulwelling, dated as of February 19, 2015 (incorporated herein by reference to Exhibit 10.14 to the Company’squarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).10.81†Stock Option Award Agreement with Eric Ulwelling, dated April 14, 2015.10.82†Employment Agreement with Kevin Nanke, dated March 6, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’s currentreport on Form 8-K filed on March 12, 2015).10.83†Stock Option Award Agreement with Kevin Nanke, dated April 14, 2015.10.84†Employment Agreement with Ariella Fuchs, dated March 16, 2015.10.85†Stock Option Award Agreement with Ariella Fuchs, dated April 14, 2015.10.86†Amended and Restated Employment Agreement between the Company and Abraham Mirman, dated March 30, 2015 (incorporated herein byreference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on April 2, 2015).10.87†Stock Option Award Agreement with Abraham Mirman, dated April 14, 2015. 58 21.1List of subsidiaries of the registrant.23.1Consent of Marcum LLP.23.2Consent of Hein & Associates, LLP.23.3Consent of RE Davis.31.1Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.31.2Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.32.1Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.32.2Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.99.1Report of RE Davis.101.INSXBRL Instance Document101.SCHXBRL Taxonomy Extension Schema Document101.CALXBRL Taxonomy Extension Calculation Linkbase Document101.DEFXBRL Taxonomy Extension Definition Linkbase Document † Indicates a management contract or any compensatory plan, contract or arrangement. 59 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Audit Committee of the Board of Directors and Shareholders of Lilis Energy, Inc. We have audited the accompanying balance sheet of Lilis Energy, Inc. (the “Company”) as of December 31, 2014, and the related statements of operations,stockholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is notrequired to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal controlover financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinionon the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining,on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis forour opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Lilis Energy, Inc., as of December 312014, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the UnitedStates of America. /s/ Marcum LLP Marcum llpNew York, NYApril 15, 2015 F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and ShareholdersLilis Energy, Inc. We have audited the accompanying consolidated balance sheet of Lilis Energy, Inc. and subsidiaries (together, the “Company”) as of December 31, 2013,and the related consolidated statements of operations, shareholders’ equity, and cash flows for the year then ended. These financial statements are theresponsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is notrequired to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal controlover financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinionon the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining,on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis forour opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Lilis Energy, Inc. andsubsidiaries as of December 31, 2013, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generallyaccepted accounting principles. As discussed in Note 2, the 2013 financial statements have been restated to correct a misstatement. /s/ Hein & Associates LLP Denver, ColoradoJune 11, 2014, except for Note 2, as to which the date is April 15, 2015 F-2 LILIS ENERGY, INC.BALANCE SHEETS December 31, December 31, 2014 2013 (Restated) AssetsCurrent assets: Cash $509,628 $165,365 Restricted cash 183,707 504,623 Accounts receivable (net of allowance of $80,000 and $50,000 at December 31, 2014 and 2013, respectively) 831,706 467,337 Prepaid assets 54,064 195,716 Commodity price derivative receivable - 6,679 Total current assets 1,579,105 1,339,720 Oil and gas properties (full cost method), at cost: Evaluated properties 46,268,756 68,213,467 Unevaluated acreage, excluded from amortization 2,885,758 18,663,569 Wells in progress, excluded from amortization 6,041,743 1,145,794 Total oil and gas properties, at cost 55,196,257 88,022,830 Less accumulated depreciation, depletion, amortization, and impairment (24,550,217) (45,457,637)Oil and gas properties at cost, net 30,646,040 42,565,193 Other assets: Office equipment net of accumulated depreciation of $107,712 and $79,558 at December 31, 2014 and 2013,respectively. 73,823 91,161 Deferred financing costs, net 60,000 294,699 Restricted cash and deposits 215,541 215,541 Total other assets 349,364 601,401 Total Assets $32,574,509 $44,506,314 The accompanying notes are an integral part of these financial statements. F-3 LILIS ENERGY, INC.BALANCE SHEETS December 31, December 31, 2014 2013 (Restated) Liabilities, Redeemable Preferred Stock and Stockholders' EquityCurrent liabilities: Dividends accrued on preferred stock $180,000 - Accrued expenses for drilling activity 5,734,131 - Accounts payable 975,749 1,239,152 Accrued expenses 1,248,995 2,133,422 Short term notes payable - 10,662,904 Total current liabilities 8,138,875 14,035,478 Long term liabilities: Asset retirement obligation 200,063 1,104,952 Term notes payable - 8,111,436 Convertible debentures, net of discount 6,840,076 14,724,366 Bristol warrant liability 393,788 - Convertible debentures conversion derivative liability 1,249,442 605,315 Total long-term liabilities 8,683,369 24,546,069 Total liabilities 16,822,244 38,581,547 Commitments and contingencies Conditionally redeemable 6% preferred stock, $0.0001 par value: 7,000 shares authorized, 2,000 shares issued andoutstanding with a liquidation preference of $2,030,000 as of December 31, 2014. No shares were outstanding as ofDecember 31, 2013 1,686,102 - Stockholders’ equity Series A Preferred stock, $0.0001 par value; stated rate $1,000:10,000,000 shares authorized, 7,500 issued andoutstanding with a liquidation preference of $7,650,000 as of December 31, 2014. No shares were issued as ofDecember 31, 2013 6,794,000 - Common stock, $0.0001 par value: 100,000,000 shares authorized; 26,988,240 and 19,671,901 shares issued andoutstanding as of December 31, 2014 and December 31, 2013, respectively 2,699 1,967 Additional paid in capital 155,097,785 121,451,232 Accumulated deficit (147,828,321) (115,528,432)Total stockholders' equity 14,066,163 5,924,767 Total Liabilities, Redeemable Preferred Stock and Stockholders’ Equity $32,574,509 $44,506,314 The accompanying notes are an integral part of these financial statements. F-4 LILIS ENERGY, INC.STATEMENTS OF OPERATIONSYears Ended December 31, 2014 and 2013 2014 2013 (Restated) Revenue: Oil sales $2,581,689 $4,312,325 Gas sales 364,732 340,609 Operating fees 182,773 148,474 Realized gain (loss) on commodity price derivatives 11,143 (17,572)Unrealized gain on commodity price derivatives - 2,475 Total revenue 3,140,337 4,786,311 Costs and expenses: Production costs 954,347 1,217,853 Production taxes 269,823 263,437 General and administrative 10,325,842 4,965,279 Depreciation, depletion and amortization 1,337,662 2,388,871 Total costs and expenses 12,887,675 8,835,440 Loss from operations before conveyance (9,747,338) (4,049,129)Loss on conveyance of oil and gas properties (2,269,760) - Loss from operations (12,017,098) (4,049,129) Other income (expenses): Other income 32,444 11,062 Inducement expense (6,661,275) - (Loss) gain on change in fair value of convertible debentures conversion derivative liability (5,526,945) 163,935 Gain on change in fair value of Bristol warrant liability 571,228 - Interest expense (4,837,025) (6,136,842)Total other expenses (16,421,573) (5,961,845) Net loss $(28,438,671) $(10,010,974)Dividend on preferred stock (341,848) - Deemed dividend Series A Convertible Preferred Stock (3,519,370) - Net loss attributable to common shareholders $(32,299,889) $(10,010,974) Net loss per common share basic and diluted $(1.23) $(0.53)Weighted average shares outstanding: Basic and diluted 26,333,161 18,990,383 The accompanying notes are an integral part of these financial statements F-5 LILIS ENERGY, INC.STATEMENTS OF STOCKHOLDERS’ EQUITYYears Ended December 31, 2014 and 2013 Additional Preferred Stock Common Stock Paid-In Accumulated Shares Amount Shares Amount Capital Deficit Total Balance, January 1, 2013 (Restated) - $- 18,394,401 $1,839 $118,296,678 $(105,517,458) $12,781,059 Common stock issued in connection with interestpayment on convertible debt - - 636,282 64 1,167,933 - 1,167,997 Common stock issued in connection with InvestmentBanking Agreement - - 100,000 10 159,990 - 160,000 Common stock issued in connection with 2013Executive and Board Compensation under theamended agreement - - 281,250 28 (28) - - Common stock issued for compensation (board andemployees) - - 259,968 26 857,097 - 857,123 Options issued to Executive Management and Boardof Directors - - - - 455,056 - 455,056 Warrants issued to service organizations for 2013services - - - - 514,506 - 514,506 Net Loss - - - - - (10,010,974) (10,010,974) Balance, December 31, 2013 (Restated) - - 19,671,901 1,967 121,451,232 (115,528,432) 5,924,767 Common stock issued in connection with January2014 private placement - - 2,959,125 296 3,557,107 - 3,557,403 Fair value of warrants issued in connections withJanuary 2014 private placement including placementwarrants - - - - 1,678,596 - 1,678,596 Common stock issued in connection with January2014 conversion of convertible debt - - 4,366,726 437 8,733,001 - 8,733,438 Common stock issued for placement fees inconnection with January 2014 conversion ofconvertible debt - - 225,000 23 686,227 - 686,250 Fair value of inducement expense in connection withdebenture conversion - - - - 6,661,275 - 6,661,275 Reclassification of conversion liability in connectionwith January 2014 conversion of convertible debt - - - 4,882,815 - 4,882,815 Preferred stock issued in connection with May 2014private placement, net 7,500 6,794,000 - - - - 6,794,000 Fair value of warrant and beneficial conversionfeature in connection with May 2014 privateplacement - - - - 3,519,370 (3,519,370) - Common stock issued for interest in connection withconvertible debt outstanding - - 1,396,129 140 1,188,299 - 1,188,439 Common shares issued for restricted stock vested - - 327,901 32 (32) - - Stock based compensation for issuance of restrictedstock - - - - 514,804 - 514,804 Stock based compensation for issuance of stockoptions - - - - 1,242,256 - 1,242,256 Common stock issued for professional services - - 90,000 9 305,040 - 305,049 Fair value of warrants issued for professional services - - - - 677,590 - 677,590 Adjustment for restricted stock not vested - - (2,048,542) (205) 205 - - Dividend Preferred Stockholders - - - - - (341,848) (341,848)Net Loss - - - - - (28,438,671) (28,438,671) Balance, December 31, 2014 7,500 $6,794,000 26,988,240 $2,699 $155,097,785 $(147,828,321) $14,066,163 The accompanying notes are an integral part of these financial statements. F-6 LILIS ENERGY, INC.STATEMENTS OF CASH FLOWSYears Ended December 31, 2014 and 2013 Year ended December 31, 2014 2013 (Restated) Cash flows from operating activities: Net loss $(28,438,671) $(10,010,974)Adjustments to reconcile net loss to net cash used in operating activities: Inducement expense 6,661,275 - Common stock issued to investment bank for fees related to conversion of convertible debentures 686,250 - Equity instruments issued for services and compensation 2,739,699 1,986,685 Bristol warrant liability 965,016 - Reserve on bad debt expense 30,000 - Loss on conveyance of property 2,269,760 - Loss (gain) from hedge settlements 11,143 (13,359)Change in fair value of price derivative (4,464) 6,679 Change in fair value of executive incentive bonus (105,000) - Amortization of deferred financing cost 234,699 680,157 Common stock issued for convertible note interest 1,188,439 1,167,997 Change in fair value of convertible debenture conversion derivative 5,526,945 (163,935)Change in fair value of Bristol warrant liability (571,228) - Depreciation, depletion, amortization and accretion of asset retirement obligation 1,337,662 2,388,871 Accretion of debt discount 849,147 2,144,367 Changes in operating assets and liabilities: Accounts receivable (394,369) 467,254 Restricted cash 320,916 166,758 Other assets 141,652 (182,256)Accounts payable and other accrued expenses (755,108) 129,967 Net cash used in operating activities (7,306,237) (1,231,789) Cash flows from investing activities: Acquisition of undeveloped acreage (305,000) (1,404,121)Drilling capital expenditures (190,786) (398,752)Sale of undeveloped acreage interests - 640,000 Additions of office equipment (10,815) (27,829)Investment in operating bonds - (106)Net cash used in investing activities (506,601) (1,190,808) Cash flows from financing activities: Net proceeds from issuance of Common Stock 5,236,000 - Proceeds from issuance of debt - 2,179,902 Net proceeds from issuance of Series A Convertible Preferred Stock 6,794,000 - Dividend payments on preferred stock (161,848) - Repayment of debt (3,711,051) (561,975)Net cash provided by financing activities 8,157,101 1,617,927 Increase (decrease) in cash 344,263 (804,670)Cash at beginning of year 165,365 970,035 CASH AT END OF YEAR $509,628 $165,365 Supplemental disclosure: Cash paid for interest $1,324,988 $2,096,769 Cash paid for income taxes $- $- Non-cash transactions: Common stock issued for accrued convertible debenture interest $1,188,439 $1,167,997 Acquisition of oil and gas assets for accounts payable and accrued interest $5,466,405 $- Transfer from derivative liability to equity $4,882,815 $- Issuance of Common Stock for payment of convertible debentures $8,733,438 $- Issuance of redeemable preferred stock for payment of term notes payable $1,686,102 $- Conveyance of oil and gas properties for payment of term notes payable $15,063,289 $- Conveyance of oil and gas properties for reduction in asset retirement obligation $973,132 $- Stock and warrants issued for prepaid financial advisory fees $- $674,506 Property additions for asset retirement obligation $- $101,510 The accompanying notes are an integral part of these financial statements. F-7 LILIS ENERGY, INC.NOTES TO THE FINANCIAL STATEMENTS NOTE 1 – ORGANIZATION On September 21, 2009, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC(“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to RecoveryEnergy, Inc. On December 1, 2013, Recovery Energy, Inc. changed its name to Lilis Energy, Inc. (“Lilis”, “Lilis Energy”, “we”, “our”, and the “Company”).The acquisition was accounted for as a reverse acquisition with Coronado being treated as the acquirer for accounting purposes. Accordingly, the financialstatements of Coronado and Recovery Energy have been adopted as the historical financial statements of Lilis. The Company is an independent oil and gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 65,000net acres. Lilis drills for, operates and produces oil and natural gas wells through the Company’s land holdings located in Wyoming, Colorado, and Nebraska. All references to production, sales volumes and reserves quantities are net to the Company’s interest unless otherwise indicated. NOTE 2 – RESTATEMENT AND RECLASSIFICATION In February 2015, the Company discovered an error in the valuation of the conversion derivative liability of the Company’s 8% Senior Secured ConvertibleDebentures (the “Debentures”) for the periods ended December 31, 2011, December 31, 2012, September 30, 2013, December 31, 2013, March 31, 2014 andJune 30, 2014 (together, the “Relevant Periods”). Specifically, the calculation of the derivative liability included in the Company’s financial statements forthe Relevant Periods only included the value of the price protection (anti-dilution) feature, when it should have included both the conversion option and theprice protection feature embedded in the Debentures. The changes in the fair value of the derivative resulted in additional non-cash charges to the previouslyfiled financial statements. The Company has evaluated the effect of the error on all Relevant Periods in accordance with Staff Accounting Bulletin (“SAB”) 99 and SAB 108 anddetermined that the impact of the error on its previously filed annual financial statements for the fiscal years ended December 31, 2011, December 31, 2012,and December 31, 2013 was not material. The Company has restated the immaterial amounts for the fiscal years ended December 31, 2011, December 31,2012, and December 31, 2013 herein. The Company’s Stockholder’s Equity of January 1, 2013 was adjusted upward by $699,000 to reflect the restatementimpact for the fiscal years ended December 31, 2011 and 2012. Additionally in 2013, the Company increased convertible note payable, net of discount by$137,748, decrease convertible notes conversion derivative liability by $544,685 resulting in a decrease in net loss of $291,911. The Company previouslyrestated the interim periods within the Relevant Periods by amending the original filings with the Securities and Exchange Commission (“SEC”) In addition, certain amounts in the 2013 consolidated financial statements have been reclassified to conform to the December 31, 2014 consolidatedfinancial statement presentation. Such reclassifications had no effect on net loss. NOTE 3 – LIQUIDITY As of December 31, 2014, the Company had a negative working capital balance and a cash balance of approximately $6.56 million and $510,000,respectively. Also as of December 31, 2014, the Company had $6.84 million, net, outstanding under its 8% Senior Secured Convertible Debentures (the“Debentures”). The Debentures (as previously amended) were to mature on January 15, 2015; however, in connection with the Company’s entry into theCredit Agreement (discussed below) in January 2015, the Company entered into an extension agreement with the holders of the Debentures which extendsthe maturity date until January 8, 2018. The maturity date of the Debentures now coincides with the maturity date of the Credit Agreement. On June 6, 2014, T.R. Winston & Company, LLC (“TR Winston”) executed a commitment to purchase or affect the purchase by third parties of an additional$15 million in Series A 8% Convertible Preferred Stock, to be consummated within ninety (90) days thereof. The agreement was subsequently extended andexpired on February 22, 2015. On February 25, 2015, the Company and TR Winston agreed in principal to a replacement commitment, pursuant to which TRWinston has agreed to purchase or affect the purchase by third parties of an additional $7.5 million in Series A 8% Convertible Preferred Stock, to beconsummated no later than February 23, 2016, with all other terms substantially the same as those of the original commitment. F-8 On January 8, 2015, the Company entered into a credit agreement with Heartland Bank (the “Credit Agreement”) which provides for a three-year seniorsecured term loan in an initial aggregate principal amount of $3.0 million, which principal amount may be increased to a maximum principal amount of$50.0 million at the request of the Company, subject to certain conditions, and pursuant to an accordion advance provision in the Credit Agreement. Theavailability of additional funds is subject to the discretion of the lenders, and is generally based on the value of the Company’s proved developed producing(“PDP”) and proved undeveloped (“PUD”) reserves. The Company intends to use proceeds borrowed under the Credit Agreement to fund producing propertyacquisitions in North America, drill wells in the core of the Company’s lease positions and to fund its working capital. As of March 31, 2015, the Company has $1.40 million in cash on hand and is currently producing approximately 70 barrels of oil equivalent (“BOE”) a dayfrom eight economically producing wells. The Company will require additional capital to satisfy its obligations; to fund its current drilling commitments, as well as its acquisition and capital budgetplans; to help fund its ongoing overhead; and to provide additional capital to generally improve its negative working capital position. The Companyanticipates that such additional funding will be provided by a combination of capital raising activities, including borrowing transactions, the sale ofadditional debt and/or equity securities, and the sale of certain assets and by the development of certain of the Company’s undeveloped properties viaarrangements with joint venture partners. If the Company is not successful in obtaining sufficient cash to fund the aforementioned capital requirements, theCompany would be required to curtail its expenditures, and may be required to restructure its operations, sell assets on terms which may not be deemedfavorable and/or curtail other aspects of its operations, including deferring all or portions of the Company’s capital budget. There is no assurance that anysuch funding will be available to the Company on acceptable terms, if at all. NOTE 4 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES Basis of Presentation The accompanying financial statements were prepared by the Company in accordance with generally accepted accounting principles in the United States(“U.S. GAAP”). The financial statements reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fairstatement of the results of operations and financial position. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires the Company to make a number of estimates and assumptions relating to thereported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reportedamounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluatesestimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity priceenvironment. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates arereasonable. The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirementobligations, assessments of impairment imbedded in the carrying value of undeveloped acreage and undeveloped properties, fair value of financialinstruments, including derivative liabilities, depreciation and accretion, income taxes and contingencies. Restricted Cash Short term restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities. As of December 31, 2014 and 2013,the restricted cash balance was approximately $184,000 and $505,000, respectively. At December 31, 2014 and 2013, the Company had $215,000 of non-current restricted cash for plugging bonds. F-9 Accounts Receivable The Company records actual and estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costsincurred on behalf of joint interest partners. The Company typically has the right to withhold future revenue disbursements to recover outstanding jointinterest billings on outstanding receivables from joint interest owners. Management periodically reviews accounts receivable amounts for collectability andrecords its allowance for uncollectible receivables using the allowance method based on past experience. Allowance for doubtful accounts are basedprimarily on joint interest billings for expenses related to oil and natural gas wells. Receivables which derive from sales of certain oil and gas production arecollateral under the Company’s Credit Agreement. Concentration of Credit Risk The Company's cash is invested at major financial institutions primarily within the United States. At December 31, 2014 and 2013, the Company’s cash wasmaintained in accounts that are insured up to the limit determined by the federal governmental agency. The Company may at times have balances in excessof the federally insured limits. Periodically, the Company evaluates the creditworthy of the financial institutions, and has not experienced any losses in suchaccounts. Significant Customers The Company had one major customer, Shell Trading (US), which accounted for approximately 63% and 83% of the Company’s revenues for the years endedDecember 31, 2014 and 2013, respectively. PDC Energy, a new customer in 2014, accounted for 13% of the Company’s revenue for the year endedDecember 31, 2014. However, the Company does not believe that the loss of a single purchaser, including Shell Trading (US) and PDC Energy, would materially affect theCompany’s business because there are numerous other purchasers in the area in which the Company sells its production. Reserves All of the reserves data included herein are estimates. Estimates of the Company’s crude oil and natural gas reserves are prepared in accordance withguidelines established by the SEC, including rule revisions designed to modernize the oil and gas company reserves reporting requirements, which theCompany implemented effective December 31, 2010. Reservoir engineering is a subjective process of estimating underground accumulations of crude oiland natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include theprojection of future production rates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the qualityof available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crudeoil and natural gas that are ultimately recovered. In addition, economic producibility of reserves is dependent on the oil and gas prices used in the reservesestimate. The Company’s reserves estimates are based on 12-month average commodity prices, unless contractual arrangements otherwise designate the priceto be used, in accordance with the SEC rules. However, oil and gas prices are volatile and, as a result, the Company’s reserves estimates may change in thefuture. Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion, and amortization “DD&A” expense. Forexample, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reservescould also result in an impairment charge, which would reduce earnings. Oil and Gas Producing Activities The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration, non-production relateddevelopment and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses,carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a creditagainst capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship betweencapitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves. F-10 The Company accounts for its unproven long-lived assets in accordance with Accounting Standards Codification (“ASC”) Topic 360-10-05, Accounting forthe Impairment or Disposal of Long-Lived Assets. ASC Topic 360-10-05 requires that long-lived assets be reviewed for impairment whenever events orchanges in circumstances indicate that the historical cost carrying value of an asset may no longer be appropriate. Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-production methodbased upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs includingcapitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred indeveloping proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, that are not otherwiseincluded in capitalized costs. The costs of undeveloped acreage are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties.When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties or the amountof the impairment is added to full cost pool which is subject to depletion calculations. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceedan amount equal to sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves and the cost of unprovedproperties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject toamortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. The present value of estimated future net cash flows was computed by applying: a flat oil price to forecast revenues from estimated future production ofproved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming thecontinuation of existing economic conditions), less any applicable future taxes. The Company did not recognize any impairment expense for the years ended December 31, 2014 and 2013, respectively. Effective as of December 31, 2014, the Company completed an assessment of its inventory of unevaluated acreage, which resulted in a transfer of $9.90million from unevaluated acreage to evaluated properties. In assessing the unevaluated acreage, the Company analyzed the expiration dates during the yearsended December 31, 2014 and 2015 of leases that are not otherwise renewable, and transferred such acreage in the amount of $6.99 million. In addition to thetransfer of near and intermediate term expirations, the Company assessed the carrying value of its remaining acreage, and concluded that an additionaltransfer of $2.91 million was necessary. No proved reserves were associated with the transferred acreage. If commodity prices stay at current early 2015 levels or decline further, the Company will incur full cost ceiling impairments in future quarters. Because theceiling calculation uses rolling 12-month average commodity prices, lower quarter-over-quarter prices in 2015 compared to 2014 will result in a lowerceiling value each quarter. This will result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges would not affect cashflow from operating activities, but would adversely affect the Company’s net income and stockholders’ equity. Wells in Progress Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produceoil and gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and theceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves orabandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations inaccordance with full cost accounting under Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended. F-11 Deferred Financing Costs As of December 31, 2014 and December 31, 2013, the Company recorded unamortized deferred financing costs of $60,000 and $295,000, respectively,related to the closing of its term loans and credit agreements. Deferred financing costs include origination (warrants issued and overriding royalty interestsassigned to Hexagon), legal and engineering fees incurred in connection with the Company's term notes, which are being amortized using the straight-linemethod, which approximated interest rate method, over the term of the loans. The Company recorded amortization expense of approximately $295,000 and$1.60 million, respectively, in the years ended December 31, 2014 and December 31, 2013. Property and Equipment Property and equipment are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. Theestimated useful lives of property and equipment range from one to seven years. The Company recorded approximately $28,000 and $2,000 of depreciationfor the years ended December 31, 2014 and December 31, 2013, respectively. Impairment of Long-lived Assets The Company accounts for long-lived assets (other than oil and gas properties) at cost. Other long-lived assets consist principally of property and equipmentand identifiable intangible assets with finite useful lives (subject to amortization, depletion, and depreciation). The Company may impair these assetswhenever events or changes in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured bycomparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may notbe recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference. The Company did not record an impairment on long lived assets during the years ended December 31, 2014 or 2013. Fair Value of Financial Instruments As of December 31, 2014 and 2013, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, interest anddividends payable and customer deposits approximates fair value due to the short-term nature of such items. The carrying value of the Company’s secureddebt is carried at cost as the related interest rate are at the terms approximates rates currently available to the Company. Commodity Derivative Instrument The Company utilizes swaps to reduce the effect of price changes on a portion of its future oil production. On a monthly basis, a swap requires the Companyto pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay the Company if the settlement price is lessthan the strike price. The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment ofvolatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk ofadverse price movements, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time,add incremental derivative contracts to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify theterms of current contracts in order to realize the current value of the Company's existing positions. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. TheCompany's derivative contracts have typically been arranged with one counterparty. The Company has netting arrangements with this counterparty thatprovide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. Thederivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. The Company periodicallyenters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. As of December 31,2014, the Company did not have any commodity derivative instruments outstanding. F-12 Revenue Recognition The Company records revenues from the sales of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price,title has transferred and collectability is reasonably assured. Oil and Natural Gas Revenue Sales of oil and natural gas, net of any royalties, are recognized when persuasive evidence of a sales arrangement exists, oil and natural gas have beendelivered to a custody transfer point, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale isreasonably assured, and the sales price is fixed or determinable. Virtually all of the Company’s contracts’ oil and natural gas pricing provisions are tied to aNYMEX market index, with certain local differential adjustments based on, among other factors, whether a well delivers oil or natural gas to a gathering,refinery, marketing company, or transmission line and prevailing local supply and demand conditions. The price of the oil and natural gas fluctuates toremain competitive with other local oil suppliers. Asset Retirement Obligation The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded asliabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, theliabilities are accreted for the change in their present value. For purposes of depletion calculations, the Company also includes estimated dismantlement and abandonment costs, net of salvage values, associated withfuture development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated tooperating expense using a systematic and rational method. As of December 31, 2014 and 2013, the Company recorded a related liability of approximately$200,000 and $1.1 million, respectively. The information below reconciles the value of the asset retirement obligation for the periods presented (in thousands): For the years ended December 31, 2014 2013 Balance, beginning of year $1,105 $912 Liabilities incurred 4 66 Accretion expense 64 91 Conveyance of liability with oil and gas properties conveyance (973) - Change in estimate - 36 Balance, end of year $200 $1,105 Stock Based Compensation The Company measures the fair value of stock-based compensation expense awards made to employees and directors, including stock options and employeestock purchases related to employee stock purchase plans, on the date of grant using a Black-Scholes model. Restricted stock awards are recorded at the fairmarket value of the stock on the date of grant. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratablyover the requisite service periods. The measurement of share-based compensation expense is based on several criteria, including but not limited to thevaluation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate and awardcancellation rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used indetermining share-based compensation expense and the actual factors, which become known over time. The Company may change the input factors used indetermining future share-based compensation expense. The Company accounts for warrant grants to non-employees whereby the fair values of such warrants are determined using the option pricing model at theearlier of the date at which the non-employee’s performance is complete or a performance commitment is reached. F-13 Warrant Modification Expense The Company accounts for the modification of warrants as an exchange of the old award for a new award. The incremental value is measured as the excess, ifany, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a periodexpense or amortized over the performance or vesting date. The Company estimates the incremental value of each warrant using the Black-Scholes optionpricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree ofsubjective judgment is the estimated volatility of the Company’s stock price. Net Loss per Common Share Earnings (losses) per share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earningsper share are computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assumingexercise or conversion of all potentially dilutive common shares. Potentially dilutive securities, such as shares issuable upon the conversion of debt or preferred stock, and exercise of stock purchase warrants and options, areexcluded from the calculation when their effect would be anti-dilutive. As of December 31, 2014 and 2013 shares underlying options, warrants, preferredstock and convertible debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. The Company had the following Common Stock equivalents at December 31, 2014 and 2013: December 31,2014 December 31,2013 Stock Options 3,583,333 3,800,000 Series A Preferred Stock 3,112,033 - Stock Purchase Warrants 17,007,065 6,773,913 Convertible debentures 3,423,233 3,665,859 27,125,664 14,239,772 Income Taxes The Company uses the asset and liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differencesbetween financial statement carrying amounts and the tax bases of assets and liabilities, and are measured using the tax rates expected to be in effect when thedifferences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of achange in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferredtax assets when uncertainty exists regarding their realization. The Company recognize’s tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amountrecognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized taxbenefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 2014 and 2013, theCompany has determined that no liability is required to be recognized. The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or penalties wererequired to be accrued at December 31, 2014 and December 31, 2013. Further, the Company does not expect that the total amount of unrecognized taxbenefits will significantly increase or decrease during the next 12 months. F-14 Recently Issued Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts withCustomers, and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognitionguidance throughout the Industry Topics of the Codification. In addition, ASU 2014-09 supersedes the cost guidance in Subtopic 605-35, RevenueRecognition—Construction-Type and Production-Type Contracts, and creates new Subtopic 340-40, Other Assets and Deferred Costs— Contracts withCustomers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customersin an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The amendments in ASU 2014-09 areeffective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, and early application is notpermitted. The Company is currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on its financial position andresults of operations. In June 2014, FASB issued Accounting Standards Update 2014–12, Compensation – Stock Compensation (Topic 718), which clarifies accounting for share–based payments for which the terms of an award provide that a performance target could be achieved after the requisite service period. That is the case whenan employee is eligible to retire or otherwise terminate employment before the end of the period in which a performance target could be achieved and still beeligible to vest in the award if and when the performance target is achieved. The updated guidance clarifies that such a term should be treated as aperformance condition that affects vesting. As such, the performance target should not be reflected in estimating the grant–date fair value of the award.Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent thecompensation cost attributable to the periods for which the requisite service has already been rendered. The guidance will be effective for the annual periods(and interim periods therein) ending after December 15, 2015. Early application is permitted. The Company is currently evaluating the effects of ASU 2014–12 on the financial statements. In August 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014–15, Presentation of Financial Statements – GoingConcern. The Update provides U.S. GAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’sability to continue as a going concern and about related footnote disclosures. For each reporting period, management will be required to evaluate whetherthere are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date thefinancial statements are issued. This Accounting Standards Update is the final version of Proposed Accounting Standards Update 2013–300—Presentation ofFinancial Statements (Topic 205): Disclosure of Uncertainties about an Entity’s Going Concern Presumption, which has been deleted. The Company iscurrently evaluating the effects of ASU 2014–15 on the financial statements. In November 2014, the FASB issued ASU No. 2014-16 (Topic 815) - Derivatives and Hedging, which provides clarification on how current guidance shouldbe interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share.Specifically, the amendments clarify that an entity should consider all relevant terms and features in evaluating the host contract and that no single term orfeature would necessarily determine the economic characteristics and risks of the host contract. ASU 2014-16 is effective for fiscal years, and interim periodswithin those fiscal years, beginning after December 15, 2015. The amendment should be applied on a modified retrospective basis to existing hybridfinancial instruments issued in the form of a share as of the beginning of the year for which the amendments are effective. Early adoption is permitted.Management believes that adoption of this statement is not expected to have a material effect on the accompanying financial statements. In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.The update requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amountof the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interestrate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning afterDecember 15, 2015. Early adoption permitted for financial statements that have not been previously issued. The adoption of this statement will impact futurepresentation and disclosures of the financial statements. Management does not believe that these or any other recently issued, but not yet effective accounting pronouncements, if adopted, would have a materialeffect on the accompanying condensed financial statements. F-15 NOTE 5 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS AND DIVESTITURES On September 2, 2014, the Company entered into an agreement to convey its interest in 31,725 operated net acres located in the Denver Julesburg Basin andthe associated oil and natural gas production to its then primary term loan provider Hexagon for extinguishment of all outstanding debt and accrued interestpayable for an aggregate amount of approximately $15.1 million. Pursuant to the agreement, the Company also issued to Hexagon 2,000 shares of 6%Redeemable Preferred Stock having a fair value of approximately $1.69 million. The transaction was accounted for under the full cost method of accounting for oil and natural gas operations. Under the full cost method, sales orabandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or lossrecognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to thecost center. The transfer to Hexagon represents greater than 25 percent of the Company’s proved reserves of oil and gas attributable to the full cost pool andthus the Company incurred a loss on the conveyance. Following this methodology, the following table represents an allocation of the transaction. Payment of debt and accrued interest payable $15,063,289 Add: disposition of asset retirement obligations 973,132 Total disposition of liabilities $16,036,421 Proved oil and natural gas properties $32,574,603 Accumulated depletion (22,148,686)Unproved oil and natural gas properties 6,194,162 Net oil and natural gas conveyed at cost 16,620,079 Redeemable Preferred Stock at fair value 1,686,102 Total conveyance of assets and preferred stock 18,306,181 Loss on conveyance $(2,269,760) In February 2013, the Company completed the sale of certain oil and gas properties for $640,000. In June 2013, the Company purchased a 50% working interest in a section in Laramie County, Wyoming for $743,000 with an additional $13,000 asadditions to the well equipment and intangible equipment. The purchase was classified as $300,000 into undeveloped acreage and $430,000 into oil and gasproperties. Effective as of December 31, 2014, the Company completed an assessment of its inventory of unevaluated acreage, which resulted in a transfer of $9.90million from unevaluated acreage to evaluated properties. In assessing the unevaluated acreage, the Company analyzed the expiration dates during the yearsended December 31, 2014 and 2015 of leases that are not otherwise renewable, and transferred such acreage in the amount of $6.99 million. In addition to thetransfer of near and intermediate term expirations, the Company assessed carrying value of its remaining acreage, and concluded that an additional transfer of$2.91 million was necessary. No proved reserves were associated with the transferred acreage. No impairment expense has been recognized during the years ended December 31, 2014 and 2013. If commodity prices stay at current early 2015 levels or decline further, the Company will incur full cost ceiling impairments in future quarters. Because theceiling calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 2015 compared to 2014 is a lowerceiling value each quarter. This will result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges would not affect cashflow from operating activities, but would adversely affect the Company’s net income and stockholders’ equity. Depreciation, depletion and amortization (“DD&A”) expenses related to the proved properties were approximately $1.24 million and $2.39 million for theyears ended December 31, 2014 and December 31, 2013, respectively. F-16 The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized as of December 31, 2014 and 2013 (inthousands): As of December 31, 2014 2013 Undeveloped unevaluated acreage Beginning Balance $18,664 $28,067 Lease purchases 305 368 Assets Conveyed (6,194) - Transfer and other reclassification to evaluated properties (9,889) (9,771)Total undeveloped acreage $2,886 $18,664 Wells in progress: Beginning Balance $1,146 $194 Additions 5,412 1,125 Reclassification to evaluated properties (516) (173)Total wells in progress and not subject to DD&A $6,042 $1,146 As of December 31, 2014 and December 31, 2013, the Company had $6.04 million and $1.15 million of wells in progress, respectively. Wells in progress arerelated to certain wells in the Company’s core development program within the Northern Wattenberg field. The Company has capitalized and accruedapproximately $5.73 million of costs through December 31, 2014 associated with these wells, which are currently in dispute. The dispute relates to the Company’s interest in certain producing wells and the well operator’s assertion that the Company’s interest was reduced and/oreliminated as a result of a default or a farm-out agreement. Underlying the dispute is a Joint Operating agreement (“JOA”), which provides the parties withvarious rights and obligations. On March 6, 2015, the Company filed a lawsuit against the operator. In its complaint, the Company seeks monetary damages and declaratory relief on claimsof breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing,unjust enrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint. During 2014, the Company transferred $516,000 from wells-in progress to developed oil and natural gas properties for one of its other wells in NorthernWattenberg, when it became producing and economic. The amount transferred to producing properties represents 12.5% of the total 25% interest owned bythe Company. The remaining 12.5% ownership in the well is currently being accrued at $491,000 for the authorization for expenditure to drill the wells,since the remaining ownership is being disputed by the mineral owners. The Company purchased the rights from both royalty owners which claimedownership of the mineral rights. The Company has secured its 12.5% ownership by paying both owners $100,000 (total $200,000). The payment wasrecorded as an asset to obtain the right to the minerals. By securing the interest with both interest owners, the Company’s interest will remain at 25%. The mineral owners are disputing the validity of an overriding royalty interest, and as a result, the operator of the well is currently holding revenues from theCompany until the dispute is resolved. The Company believes the well is near payout and this should be resolved in the near future. The Company iscurrently accruing the remaining 12.5% authorization of expenditure and deferring the revenue in a suspense receivable account. The Company receivednotification that the dispute between the royalty owners has been settled. As a result, the Company is working with the operator to receive payment of itsinterest. F-17 NOTE 6 - DERIVATIVES The Company periodically enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oilprices. As of December 31, 2014, the Company did not have any commodity derivative instruments. As of December 31, 2013, the Company maintained anactive commodity swap for 100 barrels of oil per day through January 31, 2014 at a price of $99.25 per barrel. The amount of gain (loss) recognized in income related to the Company’s derivative financial instruments was as follows (in thousands): For the Year EndedDecember 31, 2014 2013 Realized loss on oil price hedges $11 $(18)Unrealized gain oil price hedges $- $2 Realized gains and losses are recorded as individual swaps mature and settle. These gains and losses are recorded as income or expenses in the periods duringwhich applicable contracts settle. Swaps which are unsettled as of a balance sheet date are carried at fair market value, either as an asset or liability.Unrealized gains and losses result from mark-to-market changes in the fair value of these derivatives between balance sheet dates. NOTE 7 - FAIR VALUE OF FINANCIAL INSTRUMENTS The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs, used in the valuation methodologies inmeasuring fair value: ●Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.●Level 2 – Other inputs that are directly or indirectly observable in the marketplace.●Level 3 – Unobservable inputs which are supported by little or no market activity. The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fairvalue. The Company’s fixed rate 10% and 8% term loans and convertible debentures, respectively, are measured using Level 3 inputs. Executive Compensation In September 2013, the Company announced the appointment of Abraham Mirman as its new president. In connection with Mr. Mirman’s appointment, theCompany entered into an employment agreement with Mr. Mirman (the “Mirman Agreement”). The Mirman Agreement provides for an incentive bonuspackage that, depending upon the relative performance of the Company’s Common Stock compared to the performance of stocks of certain peer groupcompanies as measured from Mr. Mirman’s initial date of employment through December 31, 2014, may result in a cash bonus payment to Mr. Mirman of upto 3.0 times his base salary. The incentive bonus is recorded as a liability and valued at each reporting period. The Company engaged a third party tocomplete a valuation of this incentive bonus. As of December 31, 2014, the Company recorded a liability of $40,000 for accrued compensation. Mr.Mirman’s employment agreement was canceled and a new agreement was put in place on March 30, 2015. See Note 14— Subsequent Events. Derivative Instruments The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted marketprices in active markets, quotes from third parties, and the credit rating of its counterparty. The Company also performs an internal valuation to ensure thereasonableness of third-party quotes. The types of derivative instruments utilized by the Company included commodity swaps. The oil derivative markets are highly active. Although theCompany’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly tradedon an exchange. As such, the Company has classified these instruments as Level 2. In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to makeany contractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources andwillingness to meet its potential repayment obligations associated with the derivative transactions. The Company has no such derivative instruments at December 31, 2014. Asset Retirement Obligation The fair value of the Company’s asset retirement obligation liability is calculated at the point of inception by taking into account, the cost of abandoning oiland gas wells, which is based on the Company’s and/or Industry’s historical experience for similar work, or estimates from independent third-parties; theeconomic lives of its properties, which are based on estimates from reserve engineers; the inflation rate; and the credit adjusted risk-free rate, which takes intoaccount the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirementobligation liability is deemed to use Level 3 inputs. F-18 Consulting Agreement with Bristol Capital-ratchet down and revalue On September 2, 2014, the Company entered into a Consulting Agreement (the “Consulting Agreement”) with Bristol Capital, LLC (“Bristol”). Pursuant tothe Consulting Agreement, Bristol agreed to assist the Company in general corporate activities including but not limited to strategic planning; managementand business operations; introductions to further its business goals; advice and services related to the Company’s growth initiatives; and any otherconsulting or advisory services the Company reasonably requests that Bristol provide to the Company. The Consulting Agreement has a term of three years.In connection with the Consulting Agreement and as compensation for the services to be provided by Bristol thereunder, the Company issued to Bristol awarrant to purchase up to 1,000,000 shares of Common Stock at an exercise price of $2.00 per share (the “Bristol Warrant”). In addition, the Company issuedto Bristol an option to purchase up to 1,000,000 shares with no forfeitures provisions. The Bristol Option is intended as an alternative to the Bristol Warrant,and will automatically terminate upon and to the extent the Bristol Warrant is exercised. Likewise, if and to the extent the Bristol Option is exercised, theBristol Warrant will terminate. If the Company has not registered the Common Shares underlying the Bristol Warrants within six months following theexecution of the Consulting Agreement, Bristol may elect to terminate the Bristol Warrant and retain the Bristol Option, or to terminate the Bristol Optionand retain the Bristol Warrant, but in either case may only retain either the Warrant or the Option. In no event will Bristol have the right to exercise, in wholeor in part, the Bristol Warrant and/or Bristol Option for a number of shares in excess of 1,000,000. Each of the Bristol Warrant and the Bristol Option(whichever ultimately remains outstanding) has a term of five years. The Consulting Agreement does not include any cash payment. The agreement has aratchet down provision for the exercise price which will reduce the exercise price if the Company enters into another consulting agreement with a lowerexercise price. The Bristol warrant/ option will automatically ratchet down to the new price. The Company is carrying the warrant/option as a long-termderivative liability and will revalue the instrument every periodic period. The Company used a Black Scholes option pricing model to value thewarrants/options which is equivalent to a binomial option pricing model calculation on September 2, 2014 using the following variables: (i) warrants/optionsissued 1,000,000 total (as stated above, the Company will only issue a total of 1,000,000 shares of Common Stock under the option or the warrant, but nomore than 1,000,000 shares in the aggregate); (ii) stock price $1.47; (iii) exercise price $ 2.00; expected life of 5 years; volatility of 91.15%; risk free rate of1.69% for a total value of $965,000, which was expensed immediately as a change in fair value of the Bristol derivative. On December 31, 2014, theCompany revalued the warrants/option using the following variables: : (i) warrants/options issued 1,000,000 total (as stated above, the Company will onlyissue a total of 1,000,000 shares of Common Stock under the option or the warrant, but no more than 1,000,000 shares in the aggregate); (ii) stock price$0.72; (iii) exercise price $ 2.00; expected life of 4.67 years; volatility of 96.78%; risk free rate of 1.10% for a total value of $394,000, which adjusted thechange in fair value valuation of the derivative by $571,000. Convertible Debentures Conversion Derivative Liability As of December 31, 2014, the Company had $6.84 million, net, in remaining Debentures, which are convertible at any time at the holders’ option into sharesof Common Stock at $2.00 per share, or 3,423,233 underlying conversion shares. The debentures have elements of a derivative due to the potential for certainadjustments, including both the conversion option and the price protection embedded in the Debentures. The conversion option allows the Debentureholders to convert their Debentures to the underlying Common Stock at $2.00. Subject to certain adjustments, including the requirement to reset theconversion for any subsequent offering at a lower price per share amount. The Company values this conversion liability at each reporting period using aMonte Carlo pricing model. F-19 The following table provides a summary of the fair values of assets and liabilities measured at fair value (in thousands): December 31, 2014: Level 1 Level 2 Level 3 Total Liability Executive employment agreement $- $- $(40) $(40)Bristol warrant liability - - (394) (394)Convertible debenture conversion derivative liability - - (1,249) (1,249)Total liability, at fair value $- $- $(1,683) $(1,683) December 31, 2013: Level 1 Level 2 Level 3 Total Assets Commodity derivative instruments $- $7 $- $7 Total assets, at fair value - 7 - 7 Liability Executive employment agreement $- $- $(145) $(145)Convertible debenture conversion derivative liability $- $- $(605) $(605)Total liability, at fair value $- $- $(750) $(750) The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of December 31, 2014 (inthousands): Conversionderivativeliability Bristolwarrantliability Incentivebonus Total Balance at December 31, 2013 $605 $- $145 $750 Additional warrant liability - 965 - 965 Change in fair value of liability 5,527 (571) (105) 4,851 Reclassification from liability to equity (4,883) - - (4,883)Balance at December 31, 2014 $1,249 $394 $40 $1,683 The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the yearending December 31, 2014 and 2013. NOTE 8 - LOAN AGREEMENTS (thousands, except percentages) As of December 31,2014 As of December 31,2013 10% Hexagon term loans $- $18,774 8% Convertible Debentures (due 2018; 8% weighted average interest rate) 6,846 15,580 Total 6,846 34,354 Unamortized debenture discount (6) (856)Total debt, net of discount 6,840 33,498 Less: amount due within one year - (10,663)Long-term debt due after one year $6,840 $22,835 10% Term Loans As of December 31, 2013, the Company had an outstanding balance of $18.8 million on its three secured term loans with Hexagon, it’s then primary lender.The loans required the Company to make monthly payments of $225,000 consisting of interest and principal. On May 19, 2014, the Company received anextension from Hexagon of the maturity date under its term loans, from May 16, 2014 to August 15, 2014. In connection with the extension, the Companypaid a forbearance fee of $250,000 which was recorded as deferred financing cost and amortized over the extension period of the term loans. F-20 On May 30, 2014, the Company entered into the First Settlement Agreement with Hexagon, which provided for the settlement of all amounts outstandingunder the term loans. In connection with the execution of the First Settlement Agreement, the Company made an initial cash payment of $5.0 millionreducing the total principal and interest due under the term loan from $19.83 million to $14.83 million. The First Settlement Agreement required theCompany to make an additional cash payment of $5.0 million (the “Second Cash Payment”) by August 15, 2014, and at that time issue to Hexagon (i) a two-year $6.0 million unsecured note (the “Replacement Note”), bearing interest at an annual rate of 8%, requiring principal and interest payments of $90,000 permonth, and (ii) 943,208 shares of unregistered Common Stock (the “Shares”). The parties also agreed that if the Second Cash Payment was not made by June30, 2014, an additional $1.0 million in principal would be added to the Replacement Note, and if the Replacement Note was not retired by December 31,2014, the Company would issue an additional 1.0 million shares of Common Stock to Hexagon. The First Settlement Agreement was superseded by the FinalSettlement Agreement which is discussed below. On September 2, 2014, the Company entered into the Final Settlement Agreement with Hexagon which replaced the First Settlement Agreement, pursuant towhich, in exchange for full extinguishment of all amounts outstanding under the term loans (approximately $15.06 million in principal and interest as of thesettlement date), the Company assigned Hexagon the collateral securing the term loans, which consisted of approximately 32,000 net acres including 17producing wells that consisted of several economic wells which secured properties with PDP reserves and PUD reserves with a carrying value ofapproximately $16.62 million. The Company also conveyed $973,000 in asset retirement obligations (“ARO”) for the 17 active and several non-producingwells. In addition to the conveyance of oil and natural gas property, the Company issued to Hexagon 2,000 shares of 6% Conditionally Redeemable PreferredStock with a par value of $0.0001, stated value of $1,000 and dividends paid on a quarterly basis valued at approximately $1.69 million at December 31,2014. As a result of this conveyance, the Company recorded a loss on conveyance of property of $2.27 million. The 2,000 shares of Conditionally Redeemable 6% Preferred Stock were issued on September 2, 2014 with a stated rate of $1,000 per share, par $0.0001. Theshares were valued using the Monte Carlo projection model to determine the value of the preferred stock. The Company used the following inputs tocalculate the valuation of the preferred stock at conveyance. The inputs consisted of a maturity range from 13.91 to 17.29 percent, redemption probabilityrate of 50%, and other probability weighted projected inputs including acquisitions, production, and other criteria that trigger a mandatory redemption.8% Convertible Debentures In numerous separate private placement transactions between February 2011 and October 2013, the Company issued an aggregate of approximately $15.6million of Debentures, secured by mortgages on several of its properties. Outstanding debentures at December 31, 2013 was $14.7 million. The Debenturesare currently convertible at the holders' option into shares of Common Stock at $2.00 per share, subject to certain adjustments which include a convertibleoption and price protection, and bear interest at an annualized rate of 8%, payable quarterly on each May 15, August 15, November 15 and February 15 incash or, at the Company's option subject to certain conditions, in shares of Common Stock. The interest option price is calculated using a 10 day VWAPdiscounted by 5% and applied to the outstanding interest. On January 31, 2014, the Company entered into a Debenture Conversion Agreement (the “Conversion Agreement”) with all of the holders of the Debentures.Pursuant to the terms of the Conversion Agreement, $9.00 million in Debentures (approximately $8.73 million of principal and $270,000 in interest) wasconverted by the holders to shares of Common Stock at a conversion price of $2.00 per share of Common Stock. In addition, the Company issued warrants tothe Debenture holders to purchase one share of Common Stock for each share issued in connection with conversion of the Debentures, at an exercise priceequal to $2.50 per share (see Inducement Expense, discussed below). As of December 31, 2014, the Company had $6.84 million, net, remaining Debentureswhich are convertible at any time at the holders’ option into shares of Common Stock at $2.00 per share, subject to certain standard adjustments. At December 31, 2014 and December 31, 2013, the Company valued the conversion feature associated with the Debentures at $1.25 million and $605,000,respectively. The Company used the following inputs to calculate the valuation of the derivative as of December 31, 2014: volatility 70%; conversion price$2.00; stock price $2.25; and present value of conversion feature $0.47 per convertible share. For the year ended December 31, 2013, the Company valuedthe conversion derivative liability using the following inputs: volatility 70%, stock price $2.32, conversion price $4.25, risk free rate 0.38%, and presentvalue of conversion feature of $0.17 per convertible share. The Company utilized a Monte Carlo model to value both conversion features. The Companytransferred $4.88 million for the change in classification of liability to equity upon conversion of the debentures. The Company’s failure to meet its obligations under the First Settlement Agreement with Hexagon constituted a default under the term loans, which in turntriggered an event of default under the Debentures. However, the holders of the Debentures waived their right to declare a default in respect of that matterthrough the extended maturity date. The Debentures were to mature on January 15, 2015; however, as of the date of this filing, the Company has received waivers from each Debenture holdersextending the maturity date thereunder to match the maturity date of the Credit Agreement to January 8, 2018. Under the terms of the Conversion Agreement, the balance of the Debentures may be converted to Common Stock on the terms provided in the ConversionAgreement (including the terms related to the Warrants) at the election of the holder, subject to receipt of shareholder approval as required by NASDAQcontinued listing requirements. The Company intends to present proposals to approve the conversion of the remaining outstanding Debentures at its 2015annual meeting of shareholders. F-21 Convertible Debenture Interest During the year ended December 31, 2014, the Company elected to fund its interest payment for its convertible debentures with stock and issued 1,396,129shares valued at approximately $1.19 million which is an add back to accrued expense in the cash flow and further disclosed in the supplemental disclosure.The interest was accrued for the period from November 15, 2013 to December 29, 2014. Debenture Conversion Agreement As of December 31, 2014, the Company has approximately $6.84 million, net, outstanding convertible debentures. Convertible Debentures ConvertibleDebenturesDebt Discount Total Balance at 12/31/2012 $(13,400,000) $2,812,821 $(10,587,179)Accretion of debt discount - (2,144,367) (2,144,367)Add: additional convertible debentures (2,179,902) 187,082 (1,992,820) Balance at 12/31/2013 $(15,579,902) $855,536 $(14,724,366)Accretion of debt discount - (472,068) (472,068)Less: conversion of convertible debenture 8,733,437 (377,079) 8,356,358 Balance at 12/31/2014 $(6,846,465) $6,840 $(6,840,076) Inducement Expense On January 31, 2014, as discussed above, the Company entered into the Conversion Agreement with all of the holders of the Debentures. Under the terms ofthe Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures outstanding as of January 30, 2014 immediately converted toshares of Common Stock at a price of $2.00 per common share. As additional inducement for the conversions, the Company issued warrants to the convertingDebenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (the “Warrants”), for each share of Common Stockissued upon conversion of the Debentures. The Company utilized a Black Scholes option price model, with a 3 year life and 65% volatility, risk free rate of0.2%, and the market price of $3.05. The Company recorded an inducement expense of $6.66 million during the year ended December 31, 2014 for theWarrants. TR Winston acted as the investment banker for the Conversion Agreement and was compensated with 225,000 shares of Common Stock valued at amarket price of $3.05 per share. During the year ended December 31, 2014, the Company valued the investment banker compensation at $686,000, whichwas expensed immediately. Interest Expense For the year ended December 31, 2014 and 2013, the Company incurred interest expense of approximately $4.84 million and $6.14 million, respectively, ofwhich approximately $2.43 million and $4.85 million, respectively, were non-cash interest expense conveyed through property, amortization of the deferredfinancing costs, accretion of the convertible debentures payable discount, and convertible debentures interest paid in Common Stock. NOTE 9 - COMMITMENTS and CONTINGENCIES Environmental and Governmental Regulation At December 31, 2014, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to theCompany. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company hasoperations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, theunitization and pooling of properties, reports concerning operations, land use, and various other matters including taxation. Oil and gas industry legislationand administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2014 the Company hadnot been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of theCompany. F-22 Legal Proceedings The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, theCompany’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’sgeneral and administrative expenses would include amounts incurred to resolve claims made against the Company. Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene in garnishmentproceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant, Tracinda, served various writs ofgarnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock. The Companyasserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. The underlyingjudgment against Mr. Parker was appealed to the Colorado Court of Appeals and, by Order dated October 17, 2013, that Court reversed the trial court withrespect to Mr. Parker’s claims of waiver, estoppel and mitigation of damages and remanded with instruction to enter judgment for Mr. Parker. The Court ofAppeals also ordered the trial court to conduct further proceedings to determine the amount of damages to award Mr. Parker on his breach of contract claim.The trial court conducted a later hearing and found in its Findings of Fact, Conclusions of Law and Order dated January 9, 2015, in favor of Mr. Parker on hisclaim for breach of contract, awarding him $6,981,302.60. Tracinda’s Motion for Amendment of the Court’s January 9 Findings and Conclusions is pending. In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No.13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-011301 EEB) against the Company and Roger Parker inconnection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property inconnection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10,2013. A trial date has not been set and, by Order dated February 2, 2015, the Bankruptcy Court ordered that the Adversary Proceeding be held in abeyancepending final resolution of the state-court action (2011CV561). The Company is unable to predict the timing and outcome of this matter. Lilis Energy, Inc. v. Great Western Operating Company LLC, Eighth Judicial District Court for Clark County, Nevada, Case No. A-15-714879-B. On March 6,2015, the Company filed a lawsuit against the operator. The dispute relates to the Company’s interest in certain producing wells and the well operator’sassertion that the Company’s interest was reduced and/or eliminated as a result of a default or a farm-out agreement. Underlying the dispute is the JOA whichprovides the parties with various rights and obligations. In its complaint, the Company seeks monetary damages and declaratory relief on claims of breach ofcontract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjustenrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint The Company believes there is no other litigation pending that could have, individually or in the aggregate, a material adverse effect on its results ofoperations or financial condition. Operating Leases The Company leases an office space under a two year operating lease in Denver, Colorado and a one year operating lease in Melville, New York expiring inNovember 2015. Rent expense for the years ended December 31, 2014 and December 31, 2013, was $109,000 and $91,000, respectively. The Company willhave minimum lease payments of $56,000 for the year ending December 31, 2015. NOTE 10 - RELATED PARTY TRANSACTIONS Abraham Mirman The Company’s Chief Executive Officer (“CEO”) is an indirect owner of a group which converted approximately $220,000 of Debentures in connection withthe $9.00 million of Debentures converted in January 2014, and was paid $10,000 in interest at the time of the Debenture conversion. During the January 2014 private placement, Mr. Mirman entered into a subscription agreement with the Company to invest $500,000, for which Mr. Mirmanwill receive 250,000 shares of stock and 250,000 warrants. The subscription agreement will not be consummated until a shareholder meeting is conducted toreceive the required approval to allow executives and board directors the ability to participate in the offering. During the May 2014 Private Placement, Mr. Mirman invested $250,000, for which Mr. Mirman received 250 shares of Series A Preferred and 51,867warrants. In September 2013, the Company appointed Abraham Mirman as its President and in April 2014 he was appointed to serve as the Company’s ChiefExecutive Officer. Prior to joining the Company, Mr. Mirman was employed by TR Winston as its Managing Director of Investment Banking and untilSeptember 2014 continued to devote a portion of his time to serving in that role. In connection with the appointment of Mr. Mirman, the Company and TRWinston amended the investment banking agreement in place between the Company and TR Winston at that time to provide that, upon the receipt by theCompany of gross cash proceeds or drawing availability of at least $30.00 million, measured on a cumulative basis and including certain restructuringtransactions, subject to the Company’s continued employment of Mr. Mirman, TR Winston would receive from the Company a lump sum payment of $1.00million. Mr. Mirman’s compensation arrangements with TR Winston provided that upon TR Winston’s receipt from the Company of the lump sum payment,TR Winston would make a payment of $1.00 million to Mr. Mirman. The Board determined in September 2014 that the criteria for the lump sum paymenthad been met. Mr. Mirman also received, as part of his compensation arrangement with TR Winston, the 100,000 common shares of the Company that wereissued to TR Winston in conjunction with the investment banking agreement. F-23 G. Tyler Runnels The Company has participated in several transactions with TR Winston, of which G. Tyler Runnels, currently a member of the Company’s board of directors,is chairman and majority owner. Mr. Runnels also beneficially holds more than 5% of the Company’s Common Stock, including the holdings of TR Winstonand his personal holdings, and has personally participated in certain transactions with the Company. On January 22, 2014, the Company paid TR Winston a commission equal to $486,000 (equal to 8% of gross proceeds at the closing of the January PrivatePlacement). Of this $486,000 commission, $313,750 was paid in cash and $172,250 was paid in 86,125 Units. In addition, the Company paid TR Winston anon-accountable expense allowance of $182,250 (equal to 3% of gross proceeds at the closing of the January Private Placement) in cash. If the participationof certain of the Company’s current and former officers and directors, who remain committed, is approved by the Company’s shareholders, the Company willpay TR Winston an additional commission. The Units issued to TR Winston were the same Units sold in the January Private Placement and were invested inthe January Private Placement. TR Winston and G. Tyler Runnels, its majority owner, also participated as investors in the Debentures, and purchased an aggregate of $1.41 million inDebentures between February 2011 and June 2013. TR Winston, as placement agent for the Debentures, received compensation in the form of 50,000 shares, valued at $230,000 on September 8, 2012. TheCompany is amortizing the $230,000 over the life of the loan as deferred financing costs. The Company amortized $134,000 of deferred financing costs intointerest expense during the year ended December 31, 2013, and the remaining $51,000 during the year ended December 31, 2014. On April 15, 2013, the Company entered into an amendment of the Debentures to extend their maturity dates from February 8, 2014 to May 16, 2014. Inconsideration for the extended maturity date, the Company provided the holders of the Debentures an additional security interest in 15,000 acres of itsundeveloped acreage. On April 16, 2013, the Company entered into an agreement with a family trust controlled by Mr. Runnels (the “personal trust”) to issue up to an additional$5.0 million in additional Debentures to existing Debenture holders, of which $1.5 million of would be issued on or before July 16, 2013. Between June2013 through October 2013, the Company issued a total of $2.2 million in additional Debentures to existing Debenture holders. In November 2013, theCompany paid TR Winston a commission of $40,000 in connection with the sale of these Debentures. On January 31, 2014, the Company entered into the Conversion Agreement with all of the holders of the Debentures, including TR Winston and Mr.Runnels’ personal trust. Under the terms of the Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures outstanding as ofJanuary 30, 2014 immediately converted to shares of Common Stock at a price of $2.00 per common share. As additional inducement for the conversions, theCompany issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (the“Warrants”), for each share of Common Stock issued upon conversion of the Debentures. TR Winston acted as the investment banker for the ConversionAgreement and was compensated by issuing 225,000 shares of the Company’s Common Stock and valued at a market price of $3.05 per share. During theyear ended December 31, 2014, the Company valued the investment banker compensation at $686,000, which was expensed immediately. On May 19, 2014, the Company and the holders of the Debentures agreed to extend the maturity date under the Debentures until August 15, 2014, and onJune 6, 2014, they agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015. In January 2015, the Companyentered into an extension agreement which extends the maturity date of the Debentures until January 8, 2018. The maturity date of the Debentures nowcoincides with the maturity date of the Credit Agreement. Upon completion of the conversion of the remaining Debentures, TR Winston will be entitled to anadditional commission. On October 6, 2014, the Company entered into a letter agreement (the “Waiver”) with the holders of its Debentures, including TR Winston and Mr. Runnels’personal trust. Pursuant to the Waiver, the holders of the Debentures agreed to waive any Event of Default (as that term is defined in the Debentures) that mayhave occurred prior to the date of the Waiver, including any default in connection with the Hexagon term loan, and to rescind and annul any acceleration orright to acceleration that may have been triggered thereby. In exchange for the Waiver, the Company agreed that TR Winston, as representative for theholders of the Debentures, would have the right to nominate two qualified individuals to serve on the Company’s Board. Mr. Runnels is one of the qualifiednomination designees which TR Winston has elected to place on the board. On March 28, 2014, the Company and TR Winston entered into a Transaction Fee Agreement in connection the May Private Placement. Pursuant to theTransaction Fee Agreement, the Company agreed to compensate TR Winston 5% of the gross proceeds of the May Private Placement, plus a $25,000 expensereimbursement. On April 29, 2014, the Company and TR Winston amended the Transaction Fee Agreement to increase TR Winston’s compensation to 8% ofthe gross proceeds, plus an additional 1% of the gross proceeds as a non-accountable expense reimbursement in addition to the $25,000 originallycontemplated. All fees were netted against gross proceeds from the private placement. F-24 On May 30, 2014, the Company paid TR Winston a commission equal to $600,000 (equal to 8% of gross proceeds at the closing of the May PrivatePlacement). Of this $600,000 commission, $51,850 was paid in cash to TR Winston, $94,150 was paid in cash to other brokers designated by TR Winston,and remaining $454,000 was invested by TR Winston into shares of Preferred Stock. In addition, the Company paid TR Winston a non-accountable expenseallowance of $75,000 (equal to 1% of gross proceeds at the closing of the May Private Placement) in cash. From May 2013 the Company was party to a one-year, non-exclusive investment banking agreement with TR Winston, pursuant to which the Companyissued to TR Winston 100,000 common shares, 900,000 warrants to purchase Common Stock. All warrants have a term of three years and a strike price of$4.25 per share, risk free rate of 0.20% and volatility at 63%. 250,000 warrants were valued at $94,000 using a Common Stock price $1.880 and 650,000warrants were valued at $162,000 using a Common Stock price of $1.55. The Company expensed $153,000 in 2013 and the remaining $103,000 in 2014.The 100,000 shares of stock were originally valued at $160,000 which were revalued during each reporting period for a total value $137,000 of which$96,000 was expensed in 2013 and the remaining $41,000 was expensed in 2014. On June 6, 2014, TR Winston executed a commitment to purchase or affect the purchase by third parties of an additional $15 million in Series A 8%Convertible Preferred Stock, to be consummated within ninety (90) days thereof. The agreement was subsequently extended and expired on February 22,2015. On February 25, 2015, the Company and TR Winston agreed in principal to a replacement commitment, pursuant to which TR Winston has agreed that,at the request of the Company’s board, TR Winston will purchase or effect the purchase by third parties of an additional $7.5 million in Series A 8%Convertible Preferred Stock, to be consummated no later than February 23, 2016, with all other terms substantially the same as those of the originalcommitment. Ronald D. Ormand On March 20, 2014, the Company entered into an Engagement Agreement (the “Engagement Agreement”) with MLV & Co. LLC (“MLV”), pursuant towhich MLV will act as the Company’s exclusive financial advisor. Ronald D. Ormand, currently a member of the Company’s board of directors as of February2015, is the Managing Director and Head of Energy Investment Banking Group at MLV. The Engagement Agreement provides for a fee of $25,000 to be paidmonthly to MLV, subject to certain adjustments and other specific fee arrangements in connection with the nature of financial services being provided. Atotal of $150,000 was paid to MLV in 2014. Hexagon Hexagon, the Company’s former primary lender, still also holds over 5% of the Company’s Common Stock. On April 15, 2013, the Company and Hexagonagreed to amend the term loans to extend their maturity dates to May 16, 2014. Pursuant to the amendment, Hexagon agreed to (i) reduce the interest rateunder the term loans from 15% to 10% beginning retroactively with March 2013, (ii) permit the Company to make interest only payments for March, April,May, and June 2013, after which time the minimum secured term loan payment became $0.23 million, and (iii) forbear from exercising its rights under theterm loan credit agreements for any breach that may have occurred prior to the amendment. In consideration for the extended maturity date, the reducedinterest rate and minimum loan payment under the secured term loans, the Company provided Hexagon an additional security interest in 15,000 acres of itsundeveloped acreage. In addition, Hexagon and its affiliates had interests in certain of the Company’s wells independent of Hexagon’s interests under the term loans, for whichHexagon or its affiliates receive revenue and joint-interest billings. In September 2014, the Company entered into the Hexagon Settlement, in exchange for extinguishment of all outstanding debt and accrued interestobligations owed to Hexagon. See Item 7 Management Discussion and Analysis of Financial Condition and Results of Operations—Overview of 2014 andRecent Developments—Hexagon Settlement and —Results of Operations—Loss on Conveyance of oil and gas properties. NOTE 11 - INCOME TAXES The income tax provision (benefit) for the years ended December 31, 2014 and 2013 consisted of the following: December 31, 2014 2013 U.S. Federal: Current $- $- Deferred (5,279,080) (2,314,920) State and local: Current - - Deferred (337,066) (105,714) (5,616,146) (2,420,634)Change in valuation allowance 5,616,146 2,420,634 Income tax provision $- $- F-25 The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2014 and 2013 consisted of the following: December 31, 2014 2013 Deferred tax assets: Oil and gas properties and equipment $- $7,924,585 Net operating loss carry-forward 37,857,532 17,373,276 Share based compensation 1,290,482 4,369,953 Abandonment obligation 72,365 404,394 Derivative instruments 142,434 2,445 Accrued liabilities 132,574 96,469 Debt conversion costs 477,439 - Other 28,937 (92,809)Total deferred tax asset 40,001,763 30,078,313 Valuation allowance (35,694,459) (30,078,313)Deferred tax asset , net of valuation allowance $4,307,304 $- Deferred tax liabilities: Oil and gas properties and equipment $(4,307,304) $- Total deferred tax liability (4,307,304) - Net deferred tax asset (liability) $- $- Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is: For the Year Ended December 31, 2014 2013 Effective federal tax rate 34.00% 35.00%State tax rate, net of federal benefit 2.17% 1.60%Change in fair value derivative liability -7.03% 2.75%Conversion inducement expense -8.47% -%Debt discount amortization -1.08% -9.07%Change in rate -1.28% 5.01%Other permanent differences 1.44% -.36%Valuation allowance -19.75% -24.91%Net -% -% The Company is in the process of filing its federal and state tax returns for the years ended April 30, 2011, December 31, 2011, December 31, 2012, December31, 2013, and December 31, 2014. The net operating losses for these years will not be available to reduce future taxable income until the returns are filed.Assuming these returns are filed, as of December 31, 2014 and 2013, the Company had net operating loss carry-forwards for federal income tax purposes ofapproximately $104.66 million and $76.55 million, respectively, available to offset future taxable income. To the extent not utilized, the net operating losscarry-forwards as of December 31, 2014 will expire beginning in 2027. The net operating loss carryovers may be subject to reduction or limitation byapplication of Internal Revenue Code Section 382 from the result of ownership changes. A full Section 382 analysis has not been prepared and theCompany's net operating losses could be subject to limitation under Section 382. In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all ofthe deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverseexisting temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and creditcarryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive andnegative. Management had no positive evidence to consider. Negative evidence considered by management includes cumulative book and tax losses inrecent years, forecasted book and tax losses, no taxable income in available carryback years, and no tax planning strategies contemplated to realize thevalued deferred tax assets. As of December 31, 2014 and 2013, management assessed the available positive and negative evidence to estimate if sufficient future taxable income wouldbe generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in thenear future. Therefore, the Company recorded a full valuation allowance of approximately $35.7 million and $30.1 million on its deferred tax assets as ofDecember 31, 2014 and 2013, respectively. F-26 NOTE 12 - SHAREHOLDERS’ EQUITY As of December 31, 2014, the Company has 100,000,000 shares of Common Stock authorized, 10,000,000 shares of Series A Preferred Stock, and 7,000shares of Conditionally Redeemable 6% Preferred Stock authorized. Of the shares authorized, 26,988,240 shares of Common Stock, 7,500,000 shares ofSeries A Preferred Stock, and 2,000 shares of Conditionally Redeemable 6% Preferred Stock were issued and outstanding. During the year ended December 31, 2014, the Company issued 9,348,213 shares of Common Stock including 2,959,125 issued in connection with theJanuary 2014 Private Placement, 4,366,726 shares issued in connection with the January 2014 conversion of convertible Debentures, 225,000 shares issuedfor placement fees in connection with the January 2014 convertible Debentures conversion, 1,396,129 shares issued for interest owed in connection withoutstanding convertible Debentures, 327,901 shares issued for the vesting of restricted stock grants to employees, board members, or consultants, and 90,000shares issued to consultants for professional services received. The Company reduced the total common shares outstanding at December 31, 2014 by2,048,542 shares as a result of an adjustment for restricted stock granted which was forfeited before it vested. The total shares of Common Stock thenincreased during the year ended December 31, 2014 by 7,316,339, net of the adjustment for restricted stock. During the year ended December 31, 2013, the Company issued 1,277,499 shares of Common Stock, including 636,282 shares to pay interest on convertibleDebentures, 100,000 paid to TR Winston, and 596,215 shares of Common Stock as restricted stock grants to employees, board members, or consultants. January 2014 Private Placement In January 2014, the Company entered into and closed a series of subscription agreements with accredited investors, pursuant to which the Company issuedan aggregate of 2,959,125 units, with each unit consisting of (i) one share of Common Stock for $2.00 a share and (ii) one three-year warrant to purchase oneshare of Common Stock at an exercise price equal to $2.50 per share (together, the “Units”), for a purchase price of $2.00 per Unit, for aggregate grossproceeds of $5.24 million (the “January Private Placement”). The warrants became exercisable in July 2014. As of February 23, 2015, neither the CommonStock issued in the January Private Placement nor the Common Stock underlying the warrants has been registered for resale. The Company intends to file aresale registration statement during the year 2015 that will cover the Common Stock issued in the private placement and the Common Stock underlying thewarrants. The Company valued the warrants within the Unit, utilizing a Black Scholes Option Pricing Model using a volatility calculation of 65%, risk freerate at the date of grant, and a 3 year term, the relative fair value allocated to warrants were approximately $1.68 million. The Company paid TR Winston243,000 warrants valued using the Black Scholes option model at $203,000 and cash of approximately $668,000 million in financing fees to TR Winston, ofwhich approximately $172,000 was reinvested into the private placement. Series A 8% Convertible Preferred Stock On May 30, 2014, the Company consummated a private placement of 7,500 shares of Series A Preferred Stock, along with detachable warrants to purchase upto 1,556,017 shares of Common Stock, at an exercise price of $2.89 per share, for aggregate gross proceeds of $7.50 million. The Series A Preferred Stock hasa par value of $0.0001 per share, a stated value of $1,000 per share, a conversion price of $2.41 per share, and a liquidation preference to any junior securities.Except as otherwise required by law, holders of Series A Preferred Stock shall not be entitled to voting rights, except with respect to proposals to alter orchange adversely the powers, preferences or rights given to the Series A Preferred Stock, authorize or create any class of stock ranking senior to the Series APreferred Stock as to dividends, redemption or distribution of assets upon liquidation, amend its certificate of incorporation or other charter documents in anymanner that adversely affects any rights of the Preferred Stock holder, or increase the number of authorized Series A Preferred Stock. The holders of the SeriesA Preferred Stock are entitled to receive a dividend payable, at the election of the Company (subject to certain conditions as set forth in the Certificate ofDesignations), in cash or shares of Common Stock, at a rate of 8% per annum payable a day after the end of each quarter. The Series A Preferred Stock isconvertible at any time at the option of the holders, or at the Company’s discretion when the Common Stock trades above $7.50 for ten consecutive dayswith a daily dollar trading volume above $300,000. In addition, the Company has the right to redeem the shares of Series A Preferred Stock, along with anyaccrued and unpaid dividends, at any time, subject to certain conditions as set forth in the Certificate of Designations. In addition, holders of the Series APreferred Stock can require the Company to redeem the Series A Preferred upon the occurrence of certain triggering events, including (i) failure to timelydeliver shares of Common Stock after valid delivery of a notice of conversion by the holder; (ii) failure to have available a sufficient number of authorizedand unreserved shares of Common Stock to issue upon conversion; (iii) the occurrence of certain change of control transactions; (iv) the occurrence of certainevents of insolvency; and (v) the ineligibility of the Company to electronically transfer its shares via the Depository Trust Company or another establishedclearing corporation. F-27 The Series A Preferred Stock is classified as equity based on the following criteria: i) the redemption of the instrument at the control of the Company; ii) theinstrument is convertible into a fixed amount of shares at a conversion price of $2.41; iii) the instrument is closely related to the underlying Company’sCommon Stock; iv) the conversion option is indexed to the Company’s stock; v) the conversion option cannot be settled in cash and only can be redeemedat the discretion of the Company; vi) and the Series A Preferred Stock is not considered convertible debt. In connection with the issuance of the Series A Preferred Stock, the Company also issued a warrant for 50% of the amount of shares of Common Stock intowhich the Series A Preferred Stock is convertible. In connection with issuance of the Series A Preferred Stock, the beneficial conversion feature (“BCF”) was valued at $2.21 million and the fair value of thewarrant was valued at $1.35 million. The aggregate value of the Series A Preferred Stock and warrant, valued at $3.56 million, was considered a deemeddividend and the full amount was expensed immediately. The Company determined the transaction created a beneficial conversion feature which iscalculated by taking the net proceeds of $6.79 million and valuing the warrants as of May 2014, utilizing a Black Scholes option pricing model. The inputsfor the pricing model are: $2.48 market price per share; exercise price of $2.89 per share; expected life of 3 years; volatility of 70%; and risk free rate of0.20%. The Company calculated the total consideration given to be $8.40 million comprised of $6.80 million for the Series A Preferred and $1.6 million forthe warrants. The Company deemed the value of the beneficial conversion feature to be $2.21 million and immediately accreted that amount as a deemeddividend. As of December 31, 2014, the Company has accrued a cumulative dividend for $150,000, which was paid fully in January 2015. Conditionally Redeemable 6% Preferred Stock In August 2014, the Company designated 2,000 shares of its authorized preferred stock as Conditionally Redeemable 6% Preferred Stock (“RedeemablePreferred”). All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon. The RedeemablePreferred has the same par value and stated value characteristics as the Series A Preferred Stock, yet the Conditionally Redeemable 6% Preferred Stock is notconvertible into Common Stock or any other securities of the Company. Except as otherwise required by law, holders of the Redeemable Preferred shall notbe entitled to voting rights. The Redeemable Preferred Stock bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and unpaid dividends)at any time at the Company’s option, or at the Holders option upon the Company’s achievement of certain production and reserves thresholds. Thesethresholds include, the Company’s annualized gross production average for 90 consecutive days at 2,500 BOE per day or higher or the Company’s PV-10value of its producing developed properties filed with the Securities and Exchange Commission exceeds $50 million. As of December 31, 2014, theCompany accrued $30,000 of accrued dividends during the period which was paid in full during January 2015. The total outstanding Redeemable Preferredwas valued at approximately $1.69 million at December 31, 2014. Consulting Agreements In January 2014, the Company entered into a consulting agreement with Market Development Consulting Group, Inc. (“MDC”), a public relations company.The agreement provided for the issuance by the Company of 90,000 shares of Common Stock, 350,000 warrants to purchase common shares, and cash of$5,000 a month. The 90,000 shares of Common Stock were issued on February 7, 2014 with an original market price of $3.35 for a total value of $302,000. The fair value ofthe shares amortized over the life of the contract, or until December 31, 2014 which were revalued at each reporting period. As of December 31, 2014, all ofthe shares have vested for a total value of $264,000. The 350,000 warrants were valued using the Black Scholes option pricing model with the following inputs: assumed stock price $2.33; strike price $2.33 for250,000 and $2.00 for 100,000 warrants; volatility 91%; risk free rate of 1.0%; and expected life of 5 years. The valuation yielded a value of approximately$575,000. The warrants vested immediately and the value was recognized as stock based non-employee compensation on the date of grant. In January 2013, the Company entered into two separate consulting agreements, one with MDC and one with a financial advisory firm. Each agreementprovided for the issuance by the Company of 200,000 warrants for a total of 400,000 warrants, with an exercise price of $4.25 and a total valuation of$266,000. The shares vested 25% on March 31, 2013 and will vest 25% for each quarter thereafter. The Company is valuing the warrants each quarter basedon their vesting schedule, and including the amount associated with such vesting warrants as an expense in the period of vesting. During the year endedDecember 31, 2013, the Company recognized a total expense of $266,000 for both of the consulting agreements. Investment Banking Agreement From May 2013, the Company was party to a one-year, non-exclusive investment banking agreement with TR Winston, pursuant to which the Companyissued to TR Winston 100,000 common shares, 900,000 warrants to purchase Common Stock. All warrants have a term of three years and a strike price of$4.25 per share, risk free rate of 0.20% and volatility at 63%. 250,000 warrants were valued at approximately $94,000 using a Common Stock price $1.88 and650,000 warrants were valued at approximately $162,000 using a Common Stock price of $1.55. The Company expensed $153,000 in 2013 and theremaining $103,000 in 2014. The 100,000 shares of stock were originally valued at approximately $160,000 which were revalued during each reportingperiod for a total value $137,000 of which $96,000 was expense in 2013 and the remaining $41,000 was expensed in 2014. F-28 Consulting Agreement with Bristol Capital On September 2, 2014, the Company entered into a Consulting Agreement (the “Consulting Agreement”) with Bristol Capital, LLC (“Bristol”). Pursuant tothe Consulting Agreement, Bristol agreed to assist the Company in general corporate activities including but not limited to strategic planning; managementand business operations; introductions to further its business goals; advice and services related to the Company’s growth initiatives; and any otherconsulting or advisory services the Company reasonably requests that Bristol provide to the Company. The Consulting Agreement has a term of three years.In connection with the Consulting Agreement and as compensation for the services to be provided by Bristol thereunder, the Company issued to Bristol awarrant to purchase up to 1,000,000 shares of Common Stock at an exercise price of $2.00 per share (the “Bristol Warrant”). In addition, the Company issuedto Bristol an option to purchase up to 1,000,000 shares with no forfeitures provisions. The Bristol Option is intended as an alternative to the Bristol Warrant,and will automatically terminate upon and to the extent the Bristol Warrant is exercised. Likewise, if and to the extent the Bristol Option is exercised, theBristol Warrant will terminate. If the Company has not registered the Common Shares underlying the Bristol Warrants within six months following theexecution of the Consulting Agreement, Bristol may elect to terminate the Bristol Warrant and retain the Bristol Option, or to terminate the Bristol Optionand retain the Bristol Warrant, but in either case may only retain either the Warrant or the Option. In no event will Bristol have the right to exercise, in wholeor in part, the Bristol Warrant and/or Bristol Option for a number of shares in excess of 1,000,000. Each of the Bristol Warrant and the Bristol Option(whichever ultimately remains outstanding) has a term of five years. The Consulting Agreement does not include any cash payment. The agreement has aratchet down provision for the exercise price which will reduce the exercise price if the Company issues securities under another consulting agreement with alower exercise price. The Bristol warrant/ option will automatically ratchet down to the new price. The Company is carrying the warrant/option as a long-term derivative liability and will revalue the instrument every periodic period. The Company used a Black Scholes option pricing model to value thewarrants/options which is equivalent to a binomial option pricing model calculation on September 2, 2014 using the following variables: (i) warrants/optionsissued 1,000,000 total (as stated above, the Company will only issue a total of 1,000,000 shares of Common Stock under the option or the warrant, but nomore than 1,000,000 shares in the aggregate); (ii) stock price $1.47; (iii) exercise price $ 2.00; expected life of 5 years; volatility of 91.15%; risk free rate of1.69% for a total value of $965,000, which was expensed immediately. On December 31, 2014, the Company re-valued the warrants/option using thefollowing variables: : (i) warrants/options issued 1,000,000 total (as stated above, the Company will only issue a total of 1,000,000 shares of Common Stockunder the option or the warrant, but no more than 1,000,000 shares in the aggregate); (ii) stock price $0.72; (iii) exercise price $ 2.00; expected life of 4.67years; volatility of 96.78%; risk free rate of 1.10% for a total value of $394,000, which resulted in a gain on the change in fair value valuation of thederivative by approximately $571,000 and recorded in other income. Convertible Debenture Interest During the years ended December 31, 2014 and 2013, the Company issued 1,396,129 and 636,282 and shares, respectively for payment of yearly interestexpense on the convertible debentures valued at $1.19 and $1.17 million, respectively. The interest option price is calculated using a 10 day VWAPdiscounted by 5% and applied to the outstanding interest. F-29 Warrants A summary of warrant activity for the twelve months ended December 31, 2014 and 2013: Warrants Weighted-AverageExercise Price Outstanding at January 1, 2013 5,638,900 $7.04 Granted 1,216,263 4.25 Exercised, forfeited, or expired (81,250) (6.00)Outstanding at December 31, 2013 6,773,913 5.24 Warrants issued in connection with conversion of debt 4,500,011 2.50 Warrants issued in connection with January 2014 private placement 2,959,125 2.50 Warrants issued to TR Winston as placement fee in January 2014 private placement 243,000 2.50 Warrants issued with Series A Preferred shares in May 2014 1,556,017 2.89 Warrants issued to Bristol (consultant) 1,000,000 2.00 Warrants issued to MDC (consultant) 100,000 2.00 Warrants issued to MDC (consultant) 250,000 2.33 Exercised, forfeited, or expired (375,000) (2.50)Outstanding at December 31, 2014 17,007,065 $3.59 The aggregate intrinsic value associated with outstanding warrants was zero at December 31, 2014 and 2013, respectively, as the strike price of all warrantsexceeded the market price for Common Stock, based on the Company’s closing Common Stock price of $0.72 and $2.32, respectively. The weighted averageremaining contract life as of December 31, 2014 was 1.71 years, and 1.56 years as of December 31, 2013. During the year ended December 31, 2014 and 2013, the Company issued warrants to purchase Common Stock for professional services. The warrants werevalued using a Black Sholes model and $ 678,000 and $515,000 were expensed immediately for the years ended December 31, 2014 and 2013, respectively. NOTE 13 - SHARE BASED AND OTHER COMPENSATION Share-Based Compensation In September 2012, the Company adopted the 2012 Equity Incentive Plan (the “EIP”). The EIP was amended by the stockholders on June 27, 2013 toincrease the number of shares of Common Stock available for grant under the EIP from 900,000 shares to 1,800,000 shares and again on November 13, 2013to increase the number of shares of Common Stock available for grant under the EIP from 1,800,000 shares to 6,800,000 shares and to increase the number ofshares of Common Stock eligible for grant under the EIP in a single year to a single participant from 1,000,000 shares to 3,000,000 shares. Each member ofthe board of directors and the management team has been periodically awarded stock options and/or restricted stock grants, and in the future may be awardedsuch grants under the terms of the EIP. The value of employee services received in exchange for an award of equity instruments are based on the grant-date fair value of the award, recognized overthe period during which an employee is required to provide services in exchange for such award. During the year ended December 31, 2014, the Company granted 324,860 shares of restricted Common Stock and 2,150,000 stock options, to employees,directors and consultants. Also during the year ended December 31, 2014, the Company forfeited 390,667 shares of restricted Common Stock and 2,366,667stock options previously issued under in connection with the termination of certain employees, directors and consultants. As a result, the Company currentlyhas 1,630,667 restricted shares and 3,583,333 options to purchase common shares outstanding to employees and directors. Options issued to employees vestin equal installments over specified time periods during the service period or upon achievement of certain performance based operating thresholds. F-30 Compensation Costs As of December 31, 2014 As of December 31, 2013 (Dollar amounts in thousands) StockOptions Restricted Stock Total StockOptions Restricted Stock Total Stock-based compensation expensed $1,242 $515 $1,757 $447 $865 $1,312 Unamortized stock-based compensationcosts $243 $107 $350 $1,368 $340 $1,708 Weighted average amortization periodremaining* 2.75 1.01 2.85 2.15 * Only includes directors and employees which the options vest over time instead of performance criteria which the performance criteria has not been met asof December 31, 2014. As of December 31, Statement of Cash Flows: 2014 2013 Common stock issued to investment bank for fees related to conversion of convertible debentures $686,250 $- Equity instruments issued for services and compensation 2,739,699 1,986,685 Bristol warrant liability 965,016 - Total non-cash compensation in Statement of Cash Flows $4,390,965 $1,986,685 Statement of Stockholder’s Equity : Common stock issued for placement fees in connection with January 2014 conversion of convertible debt $686,250 $- Stock based compensation for vesting of restricted stock 514,804 857,123 Stock based compensation for issuance of stock options 1,242,256 455,056 Common stock issued for professional services 305,049 - Fair value of warrants issued for professional services 677,590 514,506 Common stock issued in connection with Investment Banking Agreement - 160,000 Total non-cash compensation in Statement of Stockholders’ Equity 3,425,949 1,986,685 Non-equity (derivative ) Bristol Warrant 965,016 - Total non-cash compensation $4,390,965 $1,986,685 Restricted Stock A summary of restricted stock grant activity for the years ended December 31, 2014 and 2013 are presented below: Number ofShares WeightedAverageGrant DatePrice Outstanding at January 1, 2013 1,730,710 2.44 Granted 596,215 1.89 Issued (196,008) 2.33 Forfeited (106,542) 2.03 Outstanding at December 31, 2013 2,024,375 2.30 Granted 324,860 2.66 Issued (327,901) 1.88 Forfeited (390,667) 2.27 Oustanding at December 31, 2014 1,630,667 2.44 As of December 31, 2014, total unrecognized compensation cost related to the 99,166 unvested shares was approximately $169,000, which is expected to berecognized over a weighted-average remaining service period of 2 years. During the year ended December 31, 2014 and 2013, the Company issued restricted stock for professional services. The restricted stock issued was valued atthe fair market value at the date of grant and vested over the useful life of the service contract. During the years ended December 31, 2014 and 2013 theCompany amortized $515,000 and $815,000, respectively relating to these contracts. F-31 Employment and Separation Agreements W. Phillip Marcum In April 2014, the Company entered into a separation agreement (the “Marcum Agreement”) with W. Phillip Marcum, its former Chief Executive Officer, inconnection with his resignation from his positions with the Company. The Marcum Agreement provides, among other things, that, consistent with hisresignation for good reason under his Employment Agreement, the Company would pay him 12 months of severance through payroll continuation, in thegross amount of $220,000, less all applicable withholdings and taxes, that all stock options held by Mr. Marcum as of the time of his termination wouldimmediately vest, and that Mr. Marcum would remain eligible to receive any performance bonus granted by the Company to its senior executives withrespect to Company and/or executive performance in 2013. In addition, the Marcum Agreement provides that the Company would pay Mr. Marcum$150,000 in accrued base salary for his service in 2013, less all applicable withholdings and taxes, in exchange for Mr. Marcum’s forfeiture of the 93,750shares of unvested restricted Common Stock of the Company that was issued to Marcum in June 2013 in lieu of such base salary. Mr. Marcum may elect toapply amounts payable under the Marcum Agreement against his commitment to invest $125,000 in the Company’s previously disclosed private offering,upon shareholder approval of the participation of the Company’s officers and directors in that offering. The Marcum Agreement also contains certain mutualnon-disparagement covenants, as well as certain mutual confidentiality, non-solicitation and non-compete covenants. In addition, Mr. Marcum and theCompany each mutually released and discharged all known and unknown claims against the other and their respective representatives that they had orpresently may have, including claims relating to Mr. Marcum’s employment. The Marcum Agreement effectively terminated the previously disclosedEmployment Agreement entered into between Mr. Marcum and the Company, dated as of June 25, 2013, and all items were immediately accrued. In connection with the Marcum Agreement, the Company reversed the 200,000 unvested options previously issued to Mr. Marcum valued at approximately$0.07 million, and reissued fully vested options, which it valued utilizing the Black Scholes option pricing model at $0.42 million. The Company used aBlack Scholes option pricing model to value the 200,000 options which Mr. Marcum retained using the following variables: i) 200,000 options; ii) stockprice $ 3.50; iii) strike price $1.60; volatility 65%; and a total value of approximately $420,000 which was expensed immediately since under the terms ofthe Marcum Agreement, the Company was not to be provided any additional services. Robert A. Bell On May 1, 2014, Robert A. Bell entered into an employment agreement with the Company, pursuant to which he became the President and Chief OperatingOfficer. On August 1, 2014, the Company entered into a separation agreement with Mr. Bell (the “Separation Agreement”). The Separation Agreementprovides, among other things, that the Company would pay to Mr. Bell an aggregate of $100,000 in cash and issue to Mr. Bell 66,667 shares of CommonStock, in addition to satisfying the Company’s obligation to pay Mr. Bell $100,000 in cash and issue to Mr. Bell 33,333 shares of Common Stock. TheSeparation Agreement also contains certain mutual covenants, and reaffirms the survival of certain confidentiality provisions contained in Mr. Bell’semployment agreement. In addition, Mr. Bell and the Company each mutually released and discharged all known and unknown claims against the other andtheir respective representatives that they had or presently may have, including claims relating to Mr. Bell’s employment. The total amount of $206,000 wasexpensed in 2014. In connection with the termination of his employment, Mr. Bell forfeited the 1,500,000 stock options that were unvested at the time of his termination andthe Company reversed $108,000. A .Bradley Gabbard In May 2014, in connection with his resignation as CFO of the Company, A. Bradley Gabbard forfeited the 200,000 options that were unvested at the time ofhis termination, in accordance with the terms of the EIP. At the date of his resignation, the Company recorded a credit of approximately $0.07 million into theshareholder employee compensation expense account. Additionally, Mr. Gabbard forfeited his 52,084 shares of unvested restricted stock, for which theCompany recorded a reversal of approximately $59,000. Board of Directors In October 2013, the Company granted each of its independent directors 200,000 non-statutory options to purchase Common Stock at an exercise price of$2.05 per share, equal to the closing price at October 24, 2013. The options vest one-third for the next three years on the anniversary grant date. The value ofthe 600,000 options at grant date was $0.64 million and will be amortized over the vesting period. F-32 In connection with execution of an amended independent agreement, each director also agreed to receive 31,250 shares of restricted Common Stock in lieu ofa portion of their cash salaries, to vest on April 15, 2014. In December 2014, the Company issued each director 31,250 shares (total for three directors 93,750shares) for a value of $150,000. During 2014, the Company granted 650,000 options to purchase Common Stock to certain officer and directors, net of 1.50 million options granted andforfeited in 2014 described in more detail above. Additionally, the Company cancelled 867,000 options for certain officer’s directors that are no longer withthe Company. Stock Options A summary of stock options activity for the years ended December 31, 2014 and 2013 is presented below: Stock Options Outstanding andExercisable Number of Options WeightedAverageExercise Price Numberof OptionsVested/Exercisable WeightedAverageRemaining ContractualLife (Years) Outstanding at January 1, 2013 - Granted 3,800,000 $2.02 933,333 $4.28 Exercised - Forfeited or cancelled - Outstanding at December 31, 2013 3,800,000 $2.02 933,333 $4.28 Granted 2,150,000 $2.68 450,000 $4.17 Exercised - Forfeited or cancelled (2,366,667) $(2.39) - - Outstanding at December 31, 2014 3,583,333 $2.16 1,383,333 $4.24 As of December 31, 2014, total unrecognized compensation costs relating to the outstanding options was $243,000, which is expected to be recognized overthe remaining vesting period of approximately 33 months. The outstanding options do not have any intrinsic value at year end, as their weighted average price is greater than the trading price at December 31, 2014.The average life of the options is 3 years and has no intrinsic value as of December 31, 2014. During the year ended December 31, 2014 and 2013, the Company issued stock options to purchase Common Stock to certain Officers and Directors. Theoptions are valued using a Black Scholes model and amortized over the life of the option. During the years ended December 31, 2014 and 2013 the Companyamortized $515,000 and $815,000, respectively relating to options outstanding. NOTE 14- SUBSEQUENT EVENTS Debenture Conversion and Extension As discussed in detail above, the Company entered into a Conversion Agreement, with all of the holders of its Debentures to convert more than half of thethen outstanding Debentures immediately to Common Stock. The balance of the Debentures were set to mature on January 15, 2015; however, in connectionwith the Company’s entry into the Credit Agreement in January 2015, as of the date of the report, the Company has entered into an extension agreement withthe holders of the Debentures, which extends the maturity date until January 8, 2018. The maturity date now coincides with the maturity date of the CreditAgreement. F-33 Heartland Bank Credit Agreement On January 8, 2015, the Company entered into a credit agreement with Heartland Bank (the “Credit Agreement”) which provides for a three-year seniorsecured term loan in an initial aggregate principal amount of $3.0 million, which principal amount may be increased to a maximum principal amount of$50.0 million at the request of the Company, subject to certain conditions, pursuant to an accordion advance provision in the Credit Agreement. Theavailability of additional funds is subject to the discretion of the lenders, and is generally based on the value of the Company’s proved developed producing(“PDP”) and proved undeveloped (“PUD”) reserves. The Company intends to use proceeds borrowed under the Credit Agreement to fund producing propertyacquisitions in North America, drill wells in the core of the Company’s lease positions and to fund working capital. May Private Placement Also discussed in detail above, in connection with the May Private Placement, on June 6, 2014, TR Winston executed a commitment to purchase or affect thepurchase by third parties of an additional $15 million in Preferred Stock, to be consummated within ninety days thereof. The agreement was subsequentlyextended and expired on February 22, 2015. On February 25, 2015, the Company and TR Winston agreed in principal to a replacement commitment,pursuant to which TR Winston has agreed to purchase or affect the purchase by third parties of an additional $7.5 million in Preferred Stock, to beconsummated no later than February 23, 2016, with all other terms substantially the same as those of the original commitment. Employment Agreements On March 30, 2015, the Company entered into an amended and restated employment agreement (the “CEO Agreement”) with Mr. Mirman which provides fora three-year term and an annual salary of $350,000. Additionally, as of the effective date of the CEO Agreement (the “Effective Date”), Mr. Mirman was (i)granted 100,000 restricted shares of the Company’s Common Stock; (ii) paid a cash signing bonus of $100,000; and (iii) granted an incentive stock option topurchase up to 2,000,000 shares of the Company’s Common Stock, which option vests in equal installments as of the Effective Date through the secondanniversary of the Effective Date. The CEO Agreement also provides for Mr. Mirman to receive a cash incentive bonus if certain production thresholds areachieved by the Company. In addition, the CEO Agreement provides for the payment of severance to Mr. Mirman in connection with termination of hisemployment in certain circumstances, including termination by the Company without “cause” or upon Mr. Mirman’s resignation for “good reason,” in eachcase subject to Mr. Mirman’s execution, non-revocation and delivery of a release agreement. In March 2015, the Company announced the appointment of Kevin Nanke as its new Executive Vice President and Chief Financial Officer. The employmentagreement provides, among other things, that Mr. Nanke will receive an annual salary of $240,000. Additionally, as of the effective date of the employmentagreement (the “Effective Date”), Mr. Nanke was (i) granted 100,000 restricted shares of the Company’s Common Stock; (ii) paid a cash signing bonus of$100,000; and (iii) granted an incentive stock option to purchase up to 750,000 shares of the Company’s Common Stock, which option vests in equalinstallments on each of the next three anniversaries of the Effective Date. Mr. Nanke will also receive a cash incentive bonus if certain production thresholdsare achieved by the Company and a performance bonus of $100,000 if the Company achieves certain goals set forth in the employment agreement. Inaddition, Mr. Nanke’s employment agreement provides for the payment of severance to Mr. Nanke in connection with termination of his employment incertain circumstances, including termination by the Company without “cause” or upon Mr. Nanke’s resignation for “good reason,” in each case subject to Mr.Nanke’s execution, non-revocation and delivery of a release agreement. In March 2015, the Company entered into an employment agreement with Ariella Fuchs, for services to be performed as General Counsel to the Company.The employment agreement provides for an annual base salary of $230,000. Additionally, as of the effective date of the employment agreement (the“Effective Date”), Ms. Fuchs was granted (i) 50,000 restricted shares of the Company’s Common Stock and (ii) an incentive stock option to purchase up to300,000 shares of the Company’s Common Stock, which option vests in equal installments on each of the next three anniversaries of the Effective Date. Ms.Fuchs will also receive a cash incentive bonus if certain production thresholds are achieved by the Company. In addition, the employment agreementprovides for the payment of severance to Ms. Fuchs in connection with termination of her employment in certain circumstances, including termination by theCompany without “cause” or upon Ms. Fuchs’ resignation for “good reason,” in each case subject to Ms. Fuchs’ execution, non-revocation and delivery of arelease agreement. F-34 NOTE 15- SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) The following table sets forth information for the years ended December 31, 2014 and 2013 with respect to changes in the Company's proved (i.e. proveddeveloped and undeveloped) reserves: Crude Oil (Bbls) Natural Gas(Mcf) December 31, 2012 351,100 407,410 Purchase of reserves 7,825 - Revisions of previous estimates 512,023 2,238,788 Extensions, discoveries 36,325 - Sale of reserves (12,848) (17,076)Production (51,706) (64,845)December 31, 2013 842,719 2,564,277 Purchase of reserves - - Revisions of previous estimates (127,574) (862,412)Extensions, discoveries 579,991 2,715,870 Sale/conveyance of reserves (361,901) (102,540)Production (33,508) (77,954)December 31, 2014 899,727 4,237,241 Proved Developed Reserves, included above: Balance, December 31, 2012 213,306 186,017 Balance, December 31, 2013 170,531 313,358 Balance, December 31, 2014 50,185 197,146 Proved Undeveloped Reserves, included above: Balance, December 31, 2012 137,555 221,314 Balance, December 31, 2013 672,188 2,250,920 Balance, December 31, 2014 849,542 4,040,095 As of December 31, 2014 and December 31, 2013, the Company had estimated proved reserves of 899,727 and 842,719 barrels of oil, respectively and423,724 and 427,380 thousand cubic feet ("MCF") of natural gas converted to BOE, respectively. The Company’s reserves are comprised of 56% and 66%crude oil and 44% and 34% natural gas on an energy equivalent basis, as of December 31, 2014 and December 31, 2013, respectively. The following values for the December 31, 2014 and December 31, 2013 oil and gas reserves are based on the 12 month arithmetic average first of monthprice January through December 31; resulting in a natural gas price of $6.70 and $4.31 per MMBtu (NYMEX price), respectively, and crude oil price of$82.77 and $89.56 per barrel (West Texas Intermediate price), respectively. All prices are then further adjusted for transportation, quality and basisdifferentials. The following summary sets forth the Company's future net cash flows relating to proved oil and gas reserves: For the Year Ended December 31, (in thousands) 2014 2013 Future oil and gas sales $96,165 $86,521 Future production costs (22,895) (22,095)Future development costs (28,388) (21,980)Future income tax expense (1) - - Future net cash flows 44,882 42,446 10% annual discount (21,628) (19,104) Standardized measure of discounted future net cash flows $23,254 $23,342 F-35 The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands): 2014 2013 Balance at beginning of period $23,342 $15,422 Sales of oil and gas, net (1,722) (3,172)Net change in prices and production costs (262) (879)Net change in future development costs 2,781 (20,311)Extensions and discoveries 16,137 686 Acquisition of reserves - 202 Sale / conveyance of reserves (11,514) (643)Revisions of previous quantity estimates (7,842) 30,968 Previously estimated development costs incurred - - Net change in income taxes - - Accretion of discount 2,334 1,864 Other - (795)Balance at end of period $23,254 $23,342 (1)Calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all yearsreported. The Company expects that all of its Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company'soperations, and resulting NOLs, are attributable to its oil and gas assets. There were no taxes in any year as the tax basis and NOLs exceeded the futurenet revenue. A variety of methodologies are used to determine the Company’s proved reserve estimates. The principal methodologies employed are reservoir simulation,decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination ofthese methods is used to determine reserve estimates in substantially all of our fields. F-36 Exhibit 10.81RECOVERY ENERGY, INC. 2012 EQUITY INCENTIVE PLANSTOCK OPTION AWARD AGREEMENTThis Stock Option Award Agreement (the “Agreement”), is made as of the 14th day of April 2015, by and between Lilis Energy, Inc., aNevada corporation (the “Company”), and Eric Ulwelling (the “Participant”).WHEREAS, the Company desires to encourage and enable the Participant to acquire a proprietary interest in the Company throughownership of shares of the Company’s Common Stock, par value $0.0001 per share (the “Shares”), pursuant to the terms and conditions of the Company’s2012 Equity Incentive Plan (the “Plan”) and this Agreement. Such ownership will provide the Participant with additional incentive to promote the success ofthe Company; andWHEREAS, the Company and the Participant are parties to that certain Employment Agreement dated February 19, 2015 (the“Employment Agreement”).NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, theparties agree as follows:1. Definitions. For purposes of this Agreement, all capitalized terms used herein and not otherwise defined herein shall have themeanings ascribed to them in the Plan.2. Grant of Option. The Company hereby grants to the Participant options (the “Options”) to purchase up to 400,000 Shares at theexercise price (the “Exercise Price”) of the greater of the Fair Market Price (as defined in the Plan) as of the Effective Date of the Employment Agreement (asdefined in the Employment Agreement) or $2.50 per share, subject to the terms and conditions of this Agreement and the Plan.3. Expiration Date. The Options granted hereby shall expire upon the ten year anniversary of the Effective Date (such date beingthe “Expiration Date”). Except as may be otherwise set forth herein, the Options may not be exercised after the Expiration Date.4. Vesting. The Options shall vest and be exercisable by the Participant as follows:(a) Participant’s option to purchase 100,000 shares of Common Stock became exercisable on the Effective Date;(b) Participant’s option to purchase 100,000 shares of Common Stock shall become exercisable on the first anniversary ofthe Effective Date;(c) Participant’s option to purchase an additional 100,000 shares of Common Stock shall become exercisable on thesecond anniversary of the Effective Date; and1 (d) Participant’s option to purchase an additional 100,000 shares of Common Stock shall become exercisable on the thirdanniversary of the Effective Date.5. Separation from Service.(a) If the Participant’s employment is terminated by the Company for Cause (as defined in the Employment Agreement),then all Options shall terminate.(b) If the Participant terminates his employment without Good Reason (as defined in the Employment Agreement), then allOptions shall terminate on the date that is 90 days after the date of termination of the Participant’s Continuous Service (as defined in the Plan), but not laterthan the Expiration Date.(c) In the event of Participant’s Disability (as defined in the Plan), the Participant may exercise the Options at any timewithin one (1) year after the date of termination but not later than the Expiration Date.(d) In the event of Participant’s death or if a Participant should die within a period of 90 days after termination of theParticipant’s Continuous Service for reason other than Cause (as defined in the Employment Agreement), the personal representatives of the Participant’sestate or the person or persons who shall have acquired the Options from the Participant by bequest or inheritance may exercise the Options at any timewithin one (1) year after the date of death, but not later than the Expiration Date.6. Sale, Merger or Dissolution. In the event of a Change in Control (as defined in the Employment Agreement), the Companyshall give the Participant notice thereof and the Options, whether or not currently vested and exercisable, shall become immediately vested and exercisableimmediately prior to the effective date of such event, and the Board shall have the power and discretion to provide alternatives regarding the terms andconditions for the exercise of, or modification of, the Options in accordance with the Plan.7. Non-Assignability. The Option granted hereby and any right arising thereunder may not be transferred, assigned, pledged orhypothecated (whether by operation of law or otherwise), except by will or the applicable laws of descent and distribution, and the Options and any rightsarising thereunder shall not be subject to execution, attachment or similar process. The Options shall be exercisable during the lifetime of the Participant onlyby the Participant. Any attempted assignment, transfer, pledge, hypothecation or other disposition of an Option not specifically permitted herein or in thePlan shall be null and void and without effect.8. Mode of Exercise.(a) The Options may be exercised by delivery of an irrevocable notice of exercise in by the Participant to the Company,stating the number of shares being purchased.(b) The right to receive the Shares of the Company’s Common Stock upon exercise of the Options shall be conditionedupon the delivery by the Participant of payment for shares and withholding taxes incurred by reason of the exercise and certain representations, if requestedby the Administrator. Acceptable forms of consideration for exercising the Options may include:2 (1) cash, check or wire transfer (denominated in U.S. Dollars);(2) subject to the Company’s discretion to refuse for any reason and at any time to accept such consideration andsubject to any conditions or limitations established by the Administrator, other shares of the Company’s Common Stock held by the Participant which have aFair Market Value on the date of surrender equal to the aggregate exercise price of the Options to be exercised;(3) delivery of a notice that the Participant has placed a market sell order with a broker with respect to the Sharesthen issuable upon exercise of the Options, and that the broker has been directed to pay a sufficient portion of the net proceeds of the sale to the Company insatisfaction of the aggregate payments required; provided, that payment of such proceeds is then made to the Company upon settlement of such sale;(4) subject to the Company’s discretion to refuse for any reason and at any time to accept such consideration andsubject to any conditions or limitations established by the Administrator, cashless “net exercise” arrangement pursuant to which the Company will reduce thenumber of shares issued upon exercise by the largest whole number of shares having an aggregate Fair Market Value that does not exceed the aggregateexercise price, together with required withholding amounts (if any), provided that the Company shall accept a cash or other payment from the Participant tothe extent of any remaining balance not satisfied by such reduction in the number of whole shares to be issued;(5) such other consideration and method of payment for the issuance of Shares of Common Stock to the extentpermitted by Applicable Laws and acceptable to the Administrator; and(6) any combination of the foregoing methods of payment.9. Recapitalization. The number of Shares covered by the Options and the Exercise Price shall be proportionately adjusted for anyincrease or decrease in the number or type of issued Shares resulting from a stock split, reverse stock split, stock dividend, combination or reclassification ofthe Common Stock, or any other increase or decrease in the number of issued shares of Common Stock effected without receipt of consideration by theCompany. The conversion of any convertible securities of the Company shall not be deemed to have been “effected without receipt of consideration.” Suchadjustment shall be made by the Board, whose determination in that respect shall be final, binding and conclusive. 10. Plan Controlling. This Agreement is intended to conform in all respects with the requirements of the Plan. Inconsistenciesbetween the requirements of this Agreement and the Plan shall be resolved according to the terms of the Plan. The Participant acknowledges receipt of a copyof the Plan.3 11. Rights Prior to Exercise of Option. The Participant shall not have any rights as a shareholder with respect to any Shares subjectto the Option prior to the date on which he is recorded as the holder of such Shares on the records of the Company.12. Withholding Taxes. The Company shall have the right to require the Participant or his beneficiaries or legal representatives toremit to the Company an amount sufficient to satisfy any federal, state and local withholding tax requirements, including upon the grant, vesting or exerciseof this Option. Whenever payments under the Plan or this Agreement are to be made to any Participant in cash, such payments shall be net of any amountssufficient to satisfy all applicable taxes, including without limitation, all applicable federal, state and local withholding tax requirements to be withheld orsubmitted by the Company concerning such payments. The Board may, in its sole discretion, allow the Participant to satisfy withholding tax obligations byelecting to have the Company withhold from the Shares to be issued upon exercise of an Option that number of Shares having a Fair Market Value equal tothe minimum amount required to be withheld. The Fair Market Value of the Shares to be withheld shall be determined on the date that the amount of tax tobe withheld is to be determined.13. Section 409A. The Options granted hereunder are intended to comply with or be exempt from the requirements of Code Section409A, and the Agreement shall be interpreted accordingly. In no event, however, shall the Company be liable to the Participant for any tax, penalties orinterest that may be due in respect of any the Options as a result of the application of Code Section 409A, except to the extent that such tax, penalty orinterest results from a breach of this Agreement by the Company.14. Governing Law. This Agreement and all rights arising hereunder shall be governed by, and construed and interpreted inaccordance with, the laws of the State of Colorado.15. Venue; Dispute Resolutions. This Agreement shall be subject to the venue and dispute resolution provisions set forth in Sections15 and 16 of the Employment Agreement.4 NEITHER THE PLAN NOR THIS AGREEMENT SHALL BE CONSTRUED AS GIVING THE PARTICIPANT THE RIGHT TO BE RETAINED IN THEEMPLOY OR SERVICE OF THE COMPANY OR ANY AFFILIATE THEREOF, NOR SHALL THEY INTERFERE IN ANY WAY WITH THE RIGHT OF THECOMPANY OR ANY AFFILIATE THEREOF, AS APPLICABLE, TO TERMINATE THE PARTICIPANT’S EMPLOYMENT OR SERVICE AT ANY TIMEWITH OR WITHOUT CAUSE. * * * * * Executed as of the day and year first above written. LILIS ENERGY, INC. By:/s/ Abraham Mirman Name: Abraham Mirman Title: Chief Executive Officer PARTICIPANT By:/s/ Eric Ulwelling Eric Ulwelling 5Exhibit 10.83 RECOVERY ENERGY, INC.2012 EQUITY INCENTIVE PLANSTOCK OPTION AWARD AGREEMENT This Stock Option Award Agreement (the “Agreement”), is made as of the 14th day of April 2015, by and between Lilis Energy, Inc., aNevada corporation (the “Company”), and Kevin Nanke (the “Participant”). WHEREAS, the Company desires to encourage and enable the Participant to acquire a proprietary interest in the Company throughownership of shares of the Company’s Common Stock, par value $0.0001 per share (the “Shares”), pursuant to the terms and conditions of the Company’s2012 Equity Incentive Plan (the “Plan”) and this Agreement. Such ownership will provide the Participant with additional incentive to promote the success ofthe Company; and WHEREAS, the Company and the Participant are parties to that certain Employment Agreement dated March 6, 2015 (the “EmploymentAgreement”). NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, theparties agree as follows: 1. Definitions. For purposes of this Agreement, all capitalized terms used herein and not otherwise defined herein shall have themeanings ascribed to them in the Plan. 2. Grant of Option. The Company hereby grants to the Participant options (the “Options”) to purchase up to 750,000 Shares at theexercise price (the “Exercise Price”) of $0.99 per Share, subject to the terms and conditions of this Agreement and the Plan. 3. Expiration Date. The Options granted hereby shall expire upon the ten year anniversary of the Effective Date (such date being the“Expiration Date”). Except as may be otherwise set forth herein, the Options may not be exercised after the Expiration Date. 4. Vesting. The Options shall vest and be exercisable by the Participant as follows: (a) Participant’s option to purchase 250,000 shares of Common Stock shall become exercisable on the first anniversary of theEffective Date (as defined in the Employment Agreement); (b) Participant’s option to purchase an additional 250,000 shares of Common Stock shall become exercisable on the secondanniversary of the Effective Date; and (c) Participant’s option to purchase an additional 250,000 shares of Common Stock shall become exercisable on the thirdanniversary of the Effective Date.  5. Separation from Service. (a) If the Participant’s employment is terminated by the Company for Cause (as defined in the Employment Agreement), thenall Options shall terminate. (b) If the Participant terminates his employment without Good Reason (as defined in the Employment Agreement), then allOptions shall terminate on the date that is 90 days after the date of termination of the Participant’s Continuous Service (as defined in the Plan), but not laterthan the Expiration Date. (c) In the event of Participant’s Disability (as defined in the Plan), the Participant may exercise the Options at any time withinone (1) year after the date of termination but not later than the Expiration Date. (d) In the event of Participant’s death or if a Participant should die within a period of 90 days after termination of theParticipant’s Continuous Service for reason other than Cause (as defined in the Plan), the personal representatives of the Participant’s estate or the person orpersons who shall have acquired the Options from the Participant by bequest or inheritance may exercise the Options at any time within one (1) year after thedate of death, but not later than the Expiration Date. 6. Sale, Merger or Dissolution. In the event of a Change in Control (as defined in the Employment Agreement), the Company shallgive the Participant notice thereof and the Options, whether or not currently vested and exercisable, shall become immediately vested and exercisableimmediately prior to the effective date of such event, and the Board shall have the power and discretion to provide alternatives regarding the terms andconditions for the exercise of, or modification of, the Options in accordance with the Plan. 7. Non-Assignability. The Option granted hereby and any right arising thereunder may not be transferred, assigned, pledged orhypothecated (whether by operation of law or otherwise), except by will or the applicable laws of descent and distribution, and the Options and any rightsarising thereunder shall not be subject to execution, attachment or similar process. The Options shall be exercisable during the lifetime of the Participant onlyby the Participant. Any attempted assignment, transfer, pledge, hypothecation or other disposition of an Option not specifically permitted herein or in thePlan shall be null and void and without effect. 8. Mode of Exercise. (a) The Options may be exercised by delivery of an irrevocable notice of exercise in by the Participant to the Company,stating the number of shares being purchased. (b) The right to receive the Shares of the Company’s Common Stock upon exercise of the Options shall be conditioned uponthe delivery by the Participant of payment for shares and withholding taxes incurred by reason of the exercise and certain representations, if requested by theAdministrator. Acceptable forms of consideration for exercising the Options may include: (1) cash, check or wire transfer (denominated in U.S. Dollars); 2 (2) subject to the Company’s discretion to refuse for any reason and at any time to accept such consideration andsubject to any conditions or limitations established by the Administrator, other shares of the Company’s Common Stock held by the Participant which have aFair Market Value on the date of surrender equal to the aggregate exercise price of the Options to be exercised; (3) delivery of a notice that the Participant has placed a market sell order with a broker with respect to the Shares thenissuable upon exercise of the Options, and that the broker has been directed to pay a sufficient portion of the net proceeds of the sale to the Company insatisfaction of the aggregate payments required; provided, that payment of such proceeds is then made to the Company upon settlement of such sale; (4) subject to the Company’s discretion to refuse for any reason and at any time to accept such consideration andsubject to any conditions or limitations established by the Administrator, cashless “net exercise” arrangement pursuant to which the Company will reduce thenumber of shares issued upon exercise by the largest whole number of shares having an aggregate Fair Market Value that does not exceed the aggregateexercise price, together with required withholding amounts (if any), provided that the Company shall accept a cash or other payment from the Participant tothe extent of any remaining balance not satisfied by such reduction in the number of whole shares to be issued; (5) such other consideration and method of payment for the issuance of Shares of Common Stock to the extentpermitted by Applicable Laws and acceptable to the Administrator; and (6) any combination of the foregoing methods of payment. 9. Recapitalization. The number of Shares covered by the Options and the Exercise Price shall be proportionately adjusted for anyincrease or decrease in the number or type of issued Shares resulting from a stock split, reverse stock split, stock dividend, combination or reclassification ofthe Common Stock, or any other increase or decrease in the number of issued shares of Common Stock effected without receipt of consideration by theCompany. The conversion of any convertible securities of the Company shall not be deemed to have been “effected without receipt of consideration.” Suchadjustment shall be made by the Board, whose determination in that respect shall be final, binding and conclusive. 10. Plan Controlling. This Agreement is intended to conform in all respects with the requirements of the Plan. Inconsistencies betweenthe requirements of this Agreement and the Plan shall be resolved according to the terms of the Plan. The Participant acknowledges receipt of a copy of thePlan. 11. Rights Prior to Exercise of Option. The Participant shall not have any rights as a shareholder with respect to any Shares subject tothe Option prior to the date on which he is recorded as the holder of such Shares on the records of the Company. 3 12. Withholding Taxes. The Company shall have the right to require the Participant or his beneficiaries or legal representatives toremit to the Company an amount sufficient to satisfy any federal, state and local withholding tax requirements, including upon the grant, vesting or exerciseof this Option. Whenever payments under the Plan or this Agreement are to be made to any Participant in cash, such payments shall be net of any amountssufficient to satisfy all applicable taxes, including without limitation, all applicable federal, state and local withholding tax requirements to be withheld orsubmitted by the Company concerning such payments. The Board may, in its sole discretion, allow the Participant to satisfy withholding tax obligations byelecting to have the Company withhold from the Shares to be issued upon exercise of an Option that number of Shares having a Fair Market Value equal tothe minimum amount required to be withheld. The Fair Market Value of the Shares to be withheld shall be determined on the date that the amount of tax tobe withheld is to be determined. 13. Section 409A. The Options granted hereunder are intended to comply with or be exempt from the requirements of Code Section409A, and the Agreement shall be interpreted accordingly. In no event, however, shall the Company be liable to the Participant for any tax, penalties orinterest that may be due in respect of any the Options as a result of the application of Code Section 409A, except to the extent that such tax, penalty orinterest results from a breach of this Agreement by the Company. 14. Governing Law. This Agreement and all rights arising hereunder shall be governed by, and construed and interpreted inaccordance with, the laws of the State of Colorado. 15. Venue; Dispute Resolutions. This Agreement shall be subject to the venue and dispute resolution provisions set forth in Sections17 and 18 of the Employment Agreement. 4 NEITHER THE PLAN NOR THIS AGREEMENT SHALL BE CONSTRUED AS GIVING THE PARTICIPANT THE RIGHT TO BE RETAINED IN THEEMPLOY OR SERVICE OF THE COMPANY OR ANY AFFILIATE THEREOF, NOR SHALL THEY INTERFERE IN ANY WAY WITH THE RIGHT OF THECOMPANY OR ANY AFFILIATE THEREOF, AS APPLICABLE, TO TERMINATE THE PARTICIPANT’S EMPLOYMENT OR SERVICE AT ANY TIMEWITH OR WITHOUT CAUSE. * * * * * Executed as of the day and year first above written. LILIS ENERGY, INC. By:/s/ Abraham Mirman Name: Abraham Mirman Title: Chief Executive Officer PARTICIPANT By:/s/ Kevin Nanke Kevin Nanke 5Exhibit 10.84 EXECUTIVE EMPLOYMENT AGREEMENT THIS EXECUTIVE EMPLOYMENT AGREEMENT (“Agreement”) is entered into this 16th day of March, 2015 (the “Effective Date”) by andbetween Lilis Energy, Inc. (the “Company”), and Ariella Fuchs (“Executive”). Executive and the Company are referred to individually as a “Party” andcollectively as the “Parties.” WHEREAS, the Parties desire to enter into this Agreement setting forth the terms and conditions for the employment relationship between Executiveand the Company. NOW, THEREFORE, in consideration of the mutual covenants, representations, warranties and agreements contained herein, and for other valuableconsideration, the receipt and adequacy of which are hereby acknowledged, the Parties agree as follows: 1. Employment. The Parties agree that Executive’s employment with the Company is subject to the terms and conditions set forth herein. 2. Employment At-Will. The Parties understand and agree that Executive is an employee at-will, and that Executive may resign, or theCompany may terminate Executive’s employment, at any time, for any or for no reason, with or without cause or warning. 3. Position. Executive shall be employed as and hold the title of General Counsel of the Company, with such duties and responsibilities thatare customary in that position for public companies. 4. Scope of Services. Executive agrees, during the period of Executive’s employment by the Company, to devote all of Executive’s businesstime, energy and best efforts to carry out her responsibilities with respect to the business and affairs of the Company and its affiliates. In addition, the Partiesacknowledge and agree that Executive may (a) engage in and manage Executive’s passive personal investments, (b) engage in charitable and civic activities,and (c) engage in such other activities that the Company and Executive mutually agree to; provided, however, that such activities shall be permitted so longas such activities do not conflict with the business and affairs of the Company or interfere with the performance of Executive’s duties hereunder. 5. Salary, Compensation, and Benefits. 5.1 Base Salary. During Executive’s employment, the Company agrees to pay, and Executive agrees to accept, as Executive’s salaryfor all services to be rendered by Executive hereunder, a salary at an annual rate of Two Hundred Thirty Thousand Dollars ($230,000) (the “Base Salary”),payable in installments pursuant to the Company’s standard payroll practices and policies. The Base Salary may be subject to annual increases in the solediscretion of the Company. 5.2 Stock Grant. As of the Effective Date, Executive shall be granted 50,000 shares of the Company’s common stock (the “StockBonus”) pursuant to the Company’s 2012 Equity Incentive Plan (the “Plan”). 1 5.3 Option Bonus. Subject to the conditions and performance goals set forth below, the Company hereby grants, pursuant to the Plan,to the Executive on the Effective Date an incentive stock option to purchase up to 300,000 shares of the common stock of the Company at a strike priceequal to the closing share price for the Company’s common stock as reported on the national exchange on which the Company’s share price is reported at theclose of trading on the Effective Date, which shall become exercisable as follows: (a) executive’s option to purchase up to 100,000 shares of Companycommon stock shall vest and become exercisable upon the first anniversary of the Effective Date; (b) Executive’s option to purchase up to 100,000 shares ofCompany common stock shall vest and become exercisable upon the second anniversary of the Effective Date, and (c) Executive’s option to purchase up to100,000 shares of Company common stock shall vest and become exercisable upon the third anniversary of the Effective Date. 5.4 Cash Incentive Bonus. Executive shall receive a lump-sum cash payment if and to the extent that during the period between theEffective Date and the one-year anniversary of the Effective Date (the “Measurement Period”), the following conditions are satisfied (the “Incentive Bonus”),to be paid within 30 days after achievement of such condition: (a) Executive will be granted a cash bonus equal to 50% of her Base Salary payable to the Executive inthe event that, during the Measurement Period, the Company has determined that its annualized gross production average for aconsecutive 90-day period is equal to or exceeds 500 BOE per day. (b) Without duplication of the amount described in the preceding clause (a), Executive will be granteda cash bonus equal to 100% of her Base Salary payable to the Executive in the event that, during the Measurement Period, theCompany has determined that its annualized gross production average for a consecutive 90-day period is equal to or exceeds1,250 BOE per day. (c) Without duplication of the amounts described in the preceding clauses (a) and (b), Executive willbe granted a cash bonus equal to 200% of her Base Salary payable to the Executive in the event that, during the MeasurementPeriod, the Company has determined that its annualized gross production average for a consecutive 90-day period is equal to orexceeds 2,500 BOE per day. (d) Without duplication of the amounts described in the preceding clauses (a), (b) and (c), Executivewill be granted a cash bonus equal to 300% of her Base Salary payable to the Executive in the event that, during theMeasurement Period, the Company has determined that its annualized gross production average for a consecutive 90-dayperiod is equal to or exceeds 3,750 BOE per day. 2 (e) Without duplication of the amounts described in the preceding clauses (a), (b), (c) and (d),Executive will be granted a cash bonus equal to 400% of her Base Salary payable to the Executive in the event that, during theMeasurement Period, the Company has determined that its annualized gross production average for a consecutive 90-dayperiod is equal to or exceeds 5,000 BOE per day. (f) Without duplication of the amounts described in the preceding clauses (a), (b), (c), (d) and (e),Executive will be granted a cash bonus equal to 500% of her Base Salary payable to the Executive in the event that, during theMeasurement Period, the Company has determined that its annualized gross production average for a consecutive 90-dayperiod is equal to or exceeds 6,250 BOE per day. 5.5 Welfare and Benefit Plans. During Executive’s employment, (A) Executive shall be entitled to participate in all incentive,savings and retirement plans, practices, policies and programs of the Company; and (B) Executive and/or Executive’s family, as the case may be, shall beeligible to participate in, and shall receive all benefits under, all welfare benefit plans, practices, policies and programs provided by the Company (including,to the extent provided, without limitation, medical, prescription, dental, vision, disability, salary continuance, employee life insurance, group life insurance,accidental death and travel accident insurance plans and programs) (all such plans collectively, the “Plans”). Except as provided herein, the Company shallnot be required to establish or continue the Plans or take any action to cause Executive to be eligible for any Plans on a basis more favorable than thatapplicable to all its executive-level employees generally. The Company reserves the right to modify or discontinue the Plans in the Company’s solediscretion. 5.6 Reimbursement. The Company shall reimburse Executive (or, in the Company’s sole discretion, shall pay directly), uponpresentation of vouchers and other supporting documentation as the Company may reasonably require, for reasonable out-of-pocket expenses incurred byExecutive relating to the business or affairs of the Company or the performance of Executive’s duties hereunder, including, without limitation, reasonableexpenses with respect to mileage, entertainment, travel and similar items, dues for membership in professional organizations, and similar professionaldevelopment expenses, provided that the incurring of such expenses shall have been approved in accordance with the Company’s regular reimbursementprocedures and practices in effect from time to time. 5.7 Vacation. In addition to statutory holidays, Executive shall be entitled to no less than four (4) weeks paid vacation each calendaryear during Executive’s employment. Vacation shall accrue pursuant to the Company’s vacation accrual policy applicable to all employees of the Company. 5.8 Withholding. The Company may withhold from Executive’s compensation all applicable amounts required by law. 3 5.9 Reservation of Rights. The Company reserves the right to modify, suspend or discontinue any and all of the employee benefitplans, practices, policies and programs referenced in Sections 5.5 through 5.7 above at any time without recourse by Executive so long as such action is takenwith respect to senior executives generally and does not single out Executive. 6. Payments Upon Termination of Employment. 6.1 Accrued but Unpaid Salary and Bonus. In the event Executive’s employment with the Company terminates for any reason, theCompany shall pay to Executive (or, in the event of Executive’s death, to Executive’s estate or named beneficiary) (a) any Base Salary, vacation pay, expensereimbursements, and benefits that are accrued but unpaid as of the date of termination and (b) any earned but unpaid bonus for any prior or current year. 6.2 Severance. (a) Upon termination of Executive’s employment with the Company by the Company without Cause(as defined below) or upon Executive’s resignation from employment for Good Reason (as defined below), in either case absenta Change in Control (as defined below), in each case contingent upon Executive’s execution, non-revocation, and delivery of aConfidential Severance and Release Agreement in a form substantially similar to Schedule A of this Agreement (the “ReleaseAgreement”), Executive shall be entitled to the following: (i) a lump sum severance payment in an amount equal to six (6)months of the Base Salary in effect immediately prior to Executive’s last date of employment, less applicable withholdings anddeductions; and (ii) immediate and full vesting of and lifting of restrictions on any unvested shares included in the Plan. (b) Upon termination of Executive’s employment with the Company by the Company without Causeor upon Executive’s resignation from employment for Good Reason, in either case within one year of a Change in Control, ineach case contingent upon Executive’s execution, non-revocation, and delivery of the Release Agreement, Executive shall beentitled to the following: (i) a lump sum severance payment in an amount equal to twenty four (24) months of the Base Salaryin effect immediately prior to Executive’s last date of employment, less applicable withholdings and deductions; and (ii)immediate and full vesting of and lifting of restrictions on any unvested shares included in the Plan. 4 (c) The Company’s obligations under this Section 6.2 are subject to the requirements and time periodsset forth in this Section 6.2 and in the Release Agreement. Prior to receiving the payments described in this Section 6.2,Executive shall execute the Release Agreement in substantially the form attached hereto as Schedule A on or before the dateseventy-five (75) days after the last day of Executive’s employment. If Executive fails to timely execute and remit the ReleaseAgreement in substantially the form attached hereto as Schedule A, Executive waives any right to the payments provided underthis Section 6.2. The Company will have no further obligations to Executive under this Agreement or otherwise after makingpayments pursuant to this Section 6.2. Payments under this Section 6.2 shall be made within fifteen (15) days of Executive’sexecution and delivery of the Release Agreement, provided that Executive does not revoke the Release Agreement. (d) Executive agrees that payments made pursuant to this Section 6.2 shall constitute the exclusive andsole remedy for any termination of Executive’s employment, and Executive covenants not to assert or pursue any otherremedies, at law or in equity, with respect to any termination of employment. The foregoing shall not limit any of Executive’srights with regard to any rights to indemnification, advancement or payment of legal fees and costs, and coverage underdirectors and officers liability insurance. (e) During the eighteen-month period following the date of the termination of Executive’semployment, the Company shall allow Executive and her eligible dependents to continue to be covered by all medical, visionand dental benefit plans maintained by the Company under which Executive was covered immediately prior to the date ofExecutive’s termination of employment at the same active employee premium cost as a similarly situated active employee;provided, however, that in the event that Executive’s employment is terminated without Cause or as the result of a Change inControl, the Company shall pay all such expenses on behalf of the Executive and her eligible dependents during the entireeighteen-month period following the date of the termination of Executive’s employment. (f) Anything in this Agreement to the contrary notwithstanding, the Company shall have the right toterminate all payments and benefits owing to Executive pursuant to this Section 6.2 upon the Company’s discovery of anymaterial breach by Executive of Executive’s obligations under the Release Agreement or Section 8 of this Agreement. 5 7. Definitions. Capitalized terms used in this Agreement but not otherwise defined herein shall have the meaning hereby assigned to them asfollows: 7.1 “Cause” shall mean the Executive’s: (i) dishonesty (including, but not limited to, theft or embezzlement of Company funds orassets); (ii) conviction of, or guilty plea or no contest plea, to a felony charge or any misdemeanor involving moral turpitude; (iii) noncompliance in anymaterial respect with any laws or regulations, foreign or domestic, affecting the operation of the Company’s business; (iv) material violation of any lawfulexpress direction or any rule, regulation or policy established by the Company that is consistent with the terms of this Agreement; (v) material breach of thisAgreement or any other agreement with the Company or breach of the Executive’s fiduciary duties to the Company; (vi) incompetence, negligence, ormisconduct in the performance of the Executive’s duties; (vii) repeated and consistent failure to be present at work during normal business hours exceptduring vacation periods or absences due to temporary illness; (viii) abuse of alcohol or drugs which interferes with the Executive’s performance of her duties;or (ix) any conduct by Executive that may have a material adverse effect to the Company’s business or reputation. 7.2 “Change in Control” shall mean (i) one person (or more than one person acting as a group) acquires ownership of stock of theCompany that, together with the stock held by such person or group, constitutes more than 50% of the total fair market value or total voting power of thestock of the Company; provided that, a Change in Control shall not occur if any person (or more than one person acting as a group) owns more than 50% ofthe total fair market value or total voting power of the Company’s stock and acquires additional stock; (ii) one person (or more than one person acting as agroup) acquires (or has acquired during the twelve-month period ending on the date of the most recent acquisition) ownership of the Company’s stockpossessing 30% or more of the total voting power of the stock of the Company; (iii) a majority of the members of the Board are replaced during any twelve-month period by directors whose appointment or election is not endorsed by a majority of the Board before the date of appointment or election; or (iv) thesale of all or substantially all of the Company’s assets. Notwithstanding the foregoing, a Change in Control shall not occur unless such transactionconstitutes a change in the ownership of the Company, a change in effective control of the Company, or a change in the ownership of a substantial portion ofthe Company’s assets under Section 409A of the Internal Revenue Code. 7.3 “Good Reason” shall mean, in the context of a resignation by Executive, a resignation that occurs within thirty (30) daysfollowing (i) a material diminution of Executive’s duties, excluding inadvertent or isolated actions not taken in bad faith and promptly remedied after writtennotice thereof, (ii) any material reduction in Executive’s Base Salary or nonpayment of Executive’s Base Salary, (iii) any material breach of this Agreementby the Company, or (iv) a material violation by the Company of the antifraud provisions of the Federal securities laws that is not caused by Executive, asfinally determined by a court or other governmental body, provided that in the case of (iii) above, Good Reason shall only exist where Executive hasprovided the Company with written notice of the breach and, if the breach is reasonably capable of being cured within a period of fifteen (15) business days,the Company has failed to cure within fifteen (15) business days. 6 8. Confidential Information. 8.1 For the purposes of this Agreement, “Confidential Information” means all proprietary information, data, knowledge, and know-how relating, directly or indirectly, to the Company and its business, including, without limitation: (i) business plans and strategies, prospect information,financial information, investment plans, marketing plans and strategies, and/or financial plans and strategies; (ii) confidential personnel or human resourcesdata; (iii) all of the Company’s technical and business information, whether patentable or not, which is of a confidential, trade secret or proprietary character;(iv) the identity of customers; (v) existing or prospective oil or gas properties, investors, participation agreements, working, royalty or other interests; contractterms; (vi) bidding information and strategies; pricing methods or information; (vii) computer software; computer software methods and documentation; (viii)hardware; (ix) the Company’s methods of operation; (x) the procedures, forms and techniques used in servicing accounts or properties; (xi) seismic,geophysical, petrophysical, or geological data; (xii) well logs and other well data; and (xiii) any other documents, information or data that the Companyrequires to be maintained in confidence for the Company’s business success or that constitutes material non-public information under the U.S. securities laws.The list set forth above is not intended by the Company to be a comprehensive list of Confidential Information. All Confidential Information shall be treatedas Confidential Information regardless of whether it pertains to the Company or its customers and regardless of whether it is stamped as “confidential.” 8.2 Executive acknowledges that the success of the Company depends in large part on the protection of the ConfidentialInformation. Executive further acknowledges that in the course of Executive’s employment with the Company, Executive will become familiar with theCompany’s Confidential Information. Executive recognizes and acknowledges that the Confidential Information is a valuable, special and unique asset ofthe Company’s business, access to and knowledge of which are essential to the performance of Executive’s duties hereunder. Executive acknowledges thatuse or disclosure of the Confidential Information outside the performance of Executive’s job duties for the Company would cause harm and/or damage to theCompany. 8.3 Both during or after the term of Executive’s employment by the Company, Executive agrees that Executive will not, except inthe ordinary course of Executive’s employment with the Company, disclose any Confidential Information to any person, firm, business, company,corporation, association, or any other entity for any reason or purpose whatsoever. Executive also agrees that Executive will not make use of anyConfidential Information for Executive’s own purposes or for the benefit of any person, firm, business, company, corporation, or any other entity (except theCompany) under any circumstances during or after the term of Executive’s employment. Executive shall consider and treat as confidential all ConfidentialInformation in any way relating to the Company’s business and affairs, whether created by Executive or otherwise coming into Executive’s possession before,during, or after the termination of Executive’s employment. Executive shall secure and protect the Confidential Information in a manner designed to preventall access and uses thereof contrary to the terms of this Agreement. Executive further agrees that Executive shall use Executive’s best efforts to assist theCompany in identifying and preventing any use or disclosure of the Confidential Information contrary to this Agreement. 7 8.4 Executive represents and warrants that, upon separation of employment, and without any request by the Company, Executivewill return to Company any and all property, documents, and files (including all recorded media, such as papers, computer disks or other data storage devices,copies, photographs, maps, transparencies, and microfiche) that contain Confidential Information or relate in any way to Company or its business. Executiveagrees, to the extent Executive possesses any files, data, or information relating in any way to Company or its business on any personal computer, Executivewill delete those files, data, or information (and will retain no copies in any form). Executive also will return any Company tools, equipment, calling cards,credit cards, access cards or keys, any keys to any filing cabinets and/or vehicles, and all other Company property in any form prior to the last date ofemployment. 9. Equitable Remedies. The services to be rendered by Executive and the Confidential Information entrusted to Executive as a result ofExecutive’s employment by the Company are of a unique and special character, and, notwithstanding any other provision in this Agreement, any breach byExecutive of this Agreement, including a breach of Section 8 (including any subsection), will cause the Company immediate and irreparable injury anddamage, for which monetary relief would be inadequate or difficult to quantify. The Company will be entitled to, in addition to all other remedies availableto it, injunctive relief, specific performance, or any other equitable relief to prevent a breach and to secure the enforcement of the provisions of thisAgreement. It is hereby further agreed that the provisions of Section 8 are separate from and independent of the remainder of this Agreement and that theseprovisions are specifically enforceable by the Company notwithstanding any claim made by Executive against the Company. Injunctive relief may begranted immediately upon the commencement of any such action, and the Company need not post a bond to obtain temporary or permanent injunctive relief. 10. Business Opportunities. Executive shall promptly disclose to the Company all business ideas, prospects, proposals, and other opportunitiespertaining to any aspect of the Company’s business that are originated by any third parties and brought to the attention of Executive during the term ofExecutive’s employment by the Company. 11. Representations and Warranties. Executive hereby represents and warrants to the Company as follows: 11.1 Executive acknowledges the success of the Company’s business depends in large part on the protection of the ConfidentialInformation and trade secrets. Executive acknowledges Executive’s access to the Confidential Information, coupled with the personal relationships andgoodwill between the Company and its customers, would enable Executive to compete unfairly against the Company; 11.2 Executive has full power, authority, and capacity to enter into this Agreement and to perform her obligations hereunder. ThisAgreement has been voluntarily executed by Executive and constitutes a valid and binding agreement of Executive; 11.3 Executive has read this Agreement and has had the opportunity to have this Agreement reviewed by Executive’s legal counsel; 8 11.4 Given the nature of the business in which the Company is engaged, the restrictions in Section 8 above are reasonable andnecessary to protect the legitimate interests of the Company; 11.5 Executive acknowledges and agrees that Executive’s continued employment with the Company is sufficient consideration forthis Agreement; 11.6 Executive is among the Company’s executive personnel, management personnel, or officers and employees who constituteprofessional staff to executive and management personnel. Moreover, Executive acknowledges this Agreement is intended to protect the Company’s tradesecrets and Confidential Information; 11.7 To the best of Executive’s knowledge, Executive’s employment with the Company will not (1) conflict with or result in a breachof any of the provisions of, (2) constitute a default under, (3) result in the violation of, (4) give any third party the right to terminate or to accelerate anyobligation under, or (5) require any authorization, consent, approval, execution, or other action by or notice to any court or other governmental body underthe provisions of any other agreement or instrument to which Executive is a party; 11.8 Executive has not previously and will not in the future disclose to the Company any proprietary information, trade secrets, orother confidential information belonging to any previous employer; and 11.9 Executive will notify business partners and future employers of Executive’s obligations under this Agreement. 12. Waivers and Amendments. The respective rights and obligations of the Company and Executive under this Agreement may be waived(either generally or in a particular instance, either retroactively or prospectively, and either for a specified period of time or indefinitely) or amended onlywith the written consent of a duly authorized representative of the Company and Executive. The waiver by either Party of a breach of any provision of thisAgreement by the other Party shall not operate or be construed as a waiver of any subsequent breach by such other Party. The failure of either Party to insistupon strict performance of any of the terms or conditions of this Agreement shall not constitute a waiver of any of such Party’s rights hereunder. 13. Successors and Assigns. The provisions hereof shall inure to the benefit of, and be binding upon and assignable to, successors of theCompany by way of merger, consolidation or sale. Executive may not assign or delegate to any third person Executive’s obligations under this Agreement.The rights and benefits of Executive under this Agreement are personal to him (or, in the event of Executive’s death or disability, Executive’s personalrepresentative, heirs, or beneficiaries), and no such right or benefit shall be subject to voluntary or involuntary alienation, assignment or transfer. 9 14. Entire Agreement. This Agreement, including Schedule A, constitutes the full and entire understanding and agreement of the Parties withregard to the subjects hereof and supersedes in its entirety all other or prior or contemporaneous agreements, whether oral or written, with respect thereto. 15. Notices. Any notices, consents, or other communications required to be sent or given hereunder by either of the Parties shall in every casebe in writing and shall be deemed properly served if (a) delivered personally, (b) sent by registered or certified mail, in all such cases with first class postageprepaid, return receipt requested, or (c) delivered by a nationally recognized overnight courier service to the Parties at the addresses set forth below: If to the Company:Lilis Energy, Inc.Attention: Chief Executive Officer216 16th Street, Suite 1350Denver, CO 80202 If to Executive:Ariella Fuchs10 Downing Street, Apt. 5BNew York, NY 10014or to the current address listed in the Company’s records. 16. Venue and Applicable Law. This Agreement shall be interpreted and construed in accordance with the laws of the State of Colorado,without regard to its conflicts of law provisions. Venue and jurisdiction will be in the New York state or federal courts. In addition to any other relief that maybe granted by such courts, the prevailing Party in any litigation arising from this Agreement shall be entitled to an award of reasonable attorneys’ fees andexpenses incurred in connection therewith. 17. Waiver of Jury Trial. EACH OF THE PARTIES HERETO HEREBY VOLUNTARILY AND IRREVOCABLY WAIVES TRIAL BY JURY INANY ACTION OR OTHER PROCEEDING BROUGHT IN CONNECTION WITH THIS AGREEMENT OR ANY OF THE TRANSACTIONSCONTEMPLATED HEREBY. 18. Section 409A. 18.1 This Agreement is intended to comply with Section 409A of the Internal Revenue Code of 1986, as amended (“Section 409A”)and shall be construed accordingly. It is the intention of the Parties that payments or benefits payable under this Agreement shall not be subject to theadditional tax or interest imposed pursuant to Section 409A. To the extent such potential payments or benefits are or could become subject to Section 409A,the Parties shall cooperate to amend this Agreement with the goal of giving Executive the economic benefits described herein in a manner that does not resultin such tax or interest being imposed; provided, however, in no event shall the Company be liable to Executive for any taxes, interest, or penalties due as aresult of the application of Section 409A to any payments or benefits provided hereunder. 18.2 Each payment provided for in this Agreement shall, to the extent permissible under Section 409A, be deemed a separate paymentfor purposes of Section 409A. 10 18.3 Payments or benefits pursuant to this Agreement shall be treated as exempt from Section 409A to the maximum extent possibleunder Treasury Regulation Section 1.409A-1(b)(9)(v), and/or under any other exemption that may be applicable, and this Agreement shall be construedaccordingly. 18.4 All taxable expenses or other reimbursements or in-kind benefits under this Agreement shall be made on or prior to the last day ofthe taxable year following the taxable year in which such expenses were incurred by Employee. Any such taxable reimbursement or any taxable in-kindbenefits provided in one calendar year shall not affect the expenses eligible for reimbursement or in-kind benefits to be provided in any other taxable year. 18.5 Executive shall have no right to designate the date of any payment hereunder. 18.6 The definition of Good Reason is intended to constitute “good reason” as such term is used in Treas. Reg. §1.409A-1(n)(2) andshall be interpreted and construed accordingly, and to the maximum extent permitted by Section 409A and guidance thereunder, a termination for GoodReason shall be an “involuntary separation from service” as such term is used in Treas. Reg. §1.409A-1(n). For purposes of Section 6 of this Agreement,“termination” (or any similar term) when used in reference to Executive’s employment shall mean “separation from service” with the Company within themeaning of Section 409A(a)(2)(A)(i) of the Code and applicable administrative guidance issued thereunder, and Executive shall be considered to haveterminated employment with the Company when, and only when, Executive incurs a “separation from service” with the Company within the meaning ofSection 409A(a)(2)(A)(i) of the Code and applicable administrative guidance issued thereunder. 18.7 Notwithstanding any other provision of this Agreement to the contrary, if (1) on the date of Executive’s separation from service(as such term is used or defined in Code Section 409A(a)(2)(A)(i), Treasury Regulation Section 1.409A-1(h), or any successor law or regulation), any of theCompany’s equity is publicly traded on an established securities market or otherwise (within the meaning of Section 409A(a)(2)(B)(i) of the Code) and (2) asa result of such separation from service, the Executive would receive any payment that, absent the application of this sentence, would be subject to interestand additional tax imposed pursuant to Code Section 409A as a result of the application of Code Section 409A(2)(B)(i), then, to the extent necessary to avoidthe imposition of such interest and additional tax, such payment shall be deferred until the earlier of (i) 6 months after the Executive’s separation fromservice, (ii) the Executive’s death, (iii) or such earlier time as may be permitted under Code Section 409A. 19. Severability; Titles and Subtitles; Gender; Singular and Plural; Counterparts; Facsimile. 19.1 In case any provision of this Agreement shall be invalid, illegal or unenforceable, the validity, legality and enforceability of theremaining provisions of this Agreement shall not in any way be affected or impaired thereby. In the event any provision is held illegal, invalid, orunenforceable, such provision shall be limited or revised by a court of competent jurisdiction so as to give effect to the provision to the fullest extentpermitted by applicable law. 11 19.2 The titles of the sections and subsections of this Agreement are for convenience of reference only and are not to be considered inconstruing this Agreement. 19.3 The use of any gender in this Agreement shall be deemed to include the other genders, and the use of the singular in thisAgreement shall be deemed to include the plural (and vice versa), wherever appropriate. 19.4 This Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which togetherconstitute one instrument. 19.5 Counterparts of this Agreement (or applicable signature pages hereof) that are manually signed and delivered by facsimile orelectronic transmission shall be deemed to constitute signed original counterparts hereof and shall bind the Parties signing and delivering in such manner. IN WITNESS WHEREOF, the Parties hereto have executed this Agreement on the date first above specified. COMPANY: EXECUTIVE: Lilis Energy, Inc. By:/s/Abraham Mirman /s/ Ariella FuchsName:Abraham Mirman Ariella FuchsTitle:Chief Executive Officer 12 Schedule A Form of Confidential Severance and Release Agreement CONFIDENTIAL SEVERANCE AND RELEASE AGREEMENT This Confidential Severance and Release Agreement (“Agreement”) is made between (i) ________________ (“Executive”) and(ii) ___________________(the “Company”). Executive and the Company are referred to individually as a “Party” and collectively as the “Parties.” RECITALS WHEREAS, Executive’s employment with the Company ended effective [DATE]; WHEREAS, the Parties wish to resolve fully and finally potential disputes regarding Executive’s employment with the Company; and WHEREAS, in order to accomplish this end, the Parties are willing to enter into this Agreement. NOW, THEREFORE, in consideration of the mutual promises and undertakings contained herein, the Parties to this Agreement agree as follows: TERMS 1. Separation and Effective Date. Executive’s last day of employment with the Company was [DATE] (the “Separation Date”). This Agreementshall become effective on the eighth day after Executive signs this Agreement (the “Effective Date”), so long as Executive does not revoke this Agreementpursuant to Paragraph 6(g) below. Executive must elect to execute this Agreement within seventy-five (75) days of the Separation Date. In the eventExecutive does not sign the Agreement within the seventy-five day period, the terms of this Agreement are null and void and without effect. 2. Consideration. a. After the Effective Date, and on the express condition that Executive has not revoked this Agreement, (i) the Company will payExecutive a lump sum severance payment in an amount equal to six (6) months of Executive’s Base Salary in effect immediately prior to Executive’s last dateof employment, less applicable withholdings and deductions; and (ii) to the extent applicable, immediate and full vesting of and lifting of restrictions on anyunvested shares included in the 2012 Equity Incentive Plan. b. Reporting of and withholding on any payment under this Paragraph for tax purposes shall be at the discretion of the Company inconformance with applicable tax laws. If a claim is made against the Company for any additional tax or withholding in connection with or arising out of anypayment pursuant to subparagraph (a) above, Executive shall pay any such claim within thirty (30) days of being notified by the Company and agrees toindemnify the Company and hold it harmless against such claims, including, but not limited to, any taxes, attorneys’ fees, penalties, and/or interest, which areor become due from the Company. 13 3. General Release. a. Executive, for Executive and for Executive’s affiliates, successors, heirs, subrogees, assigns, principals, agents, partners,employees, associates, attorneys, and representatives, voluntarily, knowingly, and intentionally releases and discharges the Company and each of itspredecessors, successors, parents, subsidiaries, affiliates, and assigns and each of their respective officers, directors, principals, shareholders, board members,committee members, employees, agents, and attorneys from any and all claims, actions, liabilities, demands, rights, damages, costs, expenses, and attorneys’fees (including, but not limited to, any claim of entitlement for attorneys’ fees under any contract, statute, or rule of law allowing a prevailing party orplaintiff to recover attorneys’ fees) of every kind and description from the beginning of time through the Effective Date (the “Released Claims”). b. The Released Claims include, but are not limited to, those which arise out of, relate to, or are based upon: (i) Executive’semployment with the Company or the termination thereof; (ii) statements, acts, or omissions by the Parties whether in their individual or representativecapacities; (iii) express or implied agreements between the Parties, (except as provided herein) and claims under any severance plan; (iv) any stock or stockoption grant, agreement, or plan; (v) all federal, state, and municipal statutes, ordinances, and regulations, including, but not limited to, claims ofdiscrimination based on race, color, national origin, age, sex, sexual orientation, religion, disability, veteran status, whistleblower status, public policy, orany other characteristic of Executive under the Age Discrimination in Employment Act, the Older Workers Benefit Protection Act, the Americans withDisabilities Act, the Equal Pay Act, Title VII of the Civil Rights Act of 1964 (as amended), the Employee Retirement Income Security Act of 1974, theRehabilitation Act of 1973, Family and Medical Leave Act, the Worker Adjustment and Retraining Notification Act or any other federal, state, or municipallaw prohibiting discrimination or termination for any reason; (vi) state and federal common law; (vii) the failure of this Agreement, or of any otheremployment, severance, profit sharing, bonus, equity incentive or other compensatory plan to which Executive and the Company are or were parties, tocomply with, or to be operated in compliance with, Internal Revenue Code Section 409A, or any similar provision of state or local income tax; and (viii) anyclaim which was or could have been raised by Executive. 4. Unknown Facts. This Agreement includes claims of every nature and kind, known or unknown, suspected or unsuspected. Executive herebyacknowledges that Executive may hereafter discover facts different from, or in addition to, those which Executive now knows or believes to be true withrespect to this Agreement, and Executive agrees that this Agreement and the releases contained herein shall be and remain effective in all respects,notwithstanding such different or additional facts or the discovery thereof. 5. No Admission of Liability. The Parties agree that nothing contained herein, and no action taken by any Party hereto with regard to thisAgreement, shall be construed as an admission by any Party of liability or of any fact that might give rise to liability for any purpose whatsoever. 14 6. Warranties. Executive warrants and represents as follows: a. Executive has read this Agreement, and Executive agrees to the conditions and obligations set forth in it. b. Executive voluntarily executes this Agreement (i) after having been advised to consult with legal counsel, (ii) after having hadopportunity to consult with legal counsel, and (iii) without being pressured or influenced by any statement or representation or omission of any person actingon behalf of the Company including, without limitation, the officers, directors, board members, committee members, employees, agents, and attorneys for theCompany. c. Executive has no knowledge of the existence of any lawsuit, charge, or proceeding against the Company or any of its officers,directors, board members, committee members, employees, successors, affiliates, or agents arising out of or otherwise connected with any of the matters hereinreleased. Subject to the provisions of Paragraph 13 below, in the event that any such lawsuit, charge, or proceeding has been filed, Executive immediatelywill take all actions necessary to withdraw or terminate that lawsuit, charge, or proceeding. d. Executive has not previously disclosed any information which would be a violation of the confidentiality provisions set forthbelow if such disclosure were to be made after the execution of this Agreement. e. Executive has full and complete legal capacity to enter into this Agreement. f. Executive has had at least twenty-one (21) days in which to consider the terms of this Agreement. In the event that Executiveexecutes this Agreement in less time, it is with the full understanding that Executive had the full twenty-one (21) days if Executive so desired and thatExecutive was not pressured by the Company or any of its representatives or agents to take less time to consider the Agreement. In such event, Executiveexpressly intends such execution to be a waiver of any right Executive had to review the Agreement for a full twenty-one (21) days. g. Executive has been informed and understands that (i) to the extent that this Agreement waives or releases any claims Executivemight have under the Age Discrimination in Employment Act, Executive may rescind Executive’s waiver and release within seven (7) calendar days ofExecutive’s execution of this Agreement and (ii) any such rescission must be in writing and e-mailed and hand delivered to [NAME AND CONTACT INFO],within the seven-day period. 15 h. Executive admits, acknowledges, and agrees that (i) Executive is not otherwise entitled to the amount set forth in Paragraph 2 and(ii) that amount is good and sufficient consideration for this Agreement. i. Executive admits, acknowledges, and agrees that Executive has been fully and finally paid or provided all wages, compensation,vacation, bonuses, stocks, stock options, or other benefits from the Company which are or could be due to Executive under the terms of Executive’semployment with the Company, or otherwise. 7. Confidential Information. a. Except as herein provided, all discussions regarding this Agreement, including, but not limited to, the amount of consideration,offers, counteroffers, or other terms or conditions of the negotiations or the agreement reached shall be kept confidential by Executive from all persons andentities other than the Parties to this Agreement. Executive may disclose the amount received in consideration of the Agreement only if necessary (i) for thelimited purpose of making disclosures required by law to agents of the local, state, or federal governments; (ii) for the purpose of enforcing any term of thisAgreement; or (iii) in response to compulsory process, and only then after giving the Company ten (10) days advance notice of the compulsory process andaffording the Company the opportunity to obtain any necessary or appropriate protective orders. Otherwise, in response to inquiries about Executive’semployment and this matter, Executive shall state, “My employment with the Company has ended” and nothing more. b. Executive shall not use, nor disclose to any third party, any of the Company’s business, personnel, or financial information thatExecutive learned during Executive’s employment with the Company. Executive hereby expressly acknowledges that any breach of this Paragraph 7 shallresult in a claim for injunctive relief and/or damages against Executive by the Company, and possibly by others. 8. Section 409A. This Agreement is intended to comply with Section 409A of the Code and Treasury Regulations promulgated thereunder(“Section 409A”) and shall be construed accordingly. It is the intention of the Parties that payments or benefits payable under this Agreement not be subjectto the additional tax or interest imposed pursuant to Section 409A. To the extent such potential payments or benefits are or could become subject to Section409A, the Parties shall cooperate to amend this Agreement with the goal of giving Executive the economic benefits described herein in a manner that doesnot result in such tax or interest being imposed. Executive shall, at the request of the Company, take any reasonable action (or refrain from taking any action),required to comply with any correction procedure promulgated pursuant to Section 409A. Each payment to be made under this Agreement shall be a separatepayment, and a separately identifiable and determinable payment, to the fullest extent permitted under Section 409A. 9. Non-Disparagement. Executive agrees not to make to any person any statement that disparages the Company or reflects negatively on theCompany, including, but not limited to, statements regarding the Company’s financial condition, employment practices, or officers, directors, boardmembers, committee members, employees, successors, affiliates, or agents. 16 10. Cooperation. Executive agrees to cooperate with and assist the Company with any investigation, lawsuit, arbitration, or other proceeding towhich the Company is subjected. Executive will make Executive available for preparation for, and attendance of, hearings, proceedings or trial, includingpretrial discovery and trial preparation. Executive further agrees to perform all acts and execute any documents that may be necessary to carry out theprovisions of this Paragraph 10. 11. Return of Property and Information. Executive represents and warrants that, prior to Executive’s execution of this Agreement, Executivewill return to the Company any and all property, documents, and files, including any documents (in any recorded media, such as papers, computer disks orother data storage devices, copies, photographs, maps, transparencies, and microfiche) that relate in any way to the Company or the Company’s business.Executive agrees that, to the extent that Executive possesses any files, data, or information relating in any way to the Company or the Company’s business onany personal computer, Executive will delete those files, data, or information (and will retain no copies in any form). Executive also will return any tools,equipment, calling cards, credit cards, access cards or keys, any keys to any filing cabinets, vehicles, vehicle keys, and all other property in any form prior tothe date Executive executes this Agreement. 12. No Application. Executive agrees that Executive will not apply for any job or position as an employee, consultant, independent contractor,or otherwise, with the Company or its subsidiaries or affiliates. Executive warrants that no such applications are pending at the time this Agreement isexecuted. 13. Administrative Proceedings. Executive acknowledges and understands that this Agreement does not prohibit or prevent Executive fromfiling a charge with a federal agency, including the Equal Employment Opportunity Commission (the “EEOC”) or equivalent state agency or fromparticipating in a federal or state agency investigation. Notwithstanding the foregoing, Executive waives any right to any monetary recovery should anyparty, including, without limitation, any federal, state or local governmental entity or administrative agency, pursue any claims on Executive’s behalf arisingout of, relating to, or in any way connected with the Released Claims. 14. Severability. If any provision of this Agreement is held illegal, invalid, or unenforceable, such holding shall not affect any other provisionshereof. In the event any provision is held illegal, invalid, or unenforceable, such provision shall be limited so as to effect the intent of the Parties to the fullestextent permitted by applicable law. Any claim by Executive against the Company shall not constitute a defense to enforcement by the Company. 15. Assignments. The Company may assign its rights under this Agreement. No other assignment is permitted except by written permission ofthe Parties. 17 16. Enforcement. The releases contained herein do not release any claims for enforcement of the terms, conditions, or warranties contained inthis Agreement. The Parties shall be free to pursue any remedies available to them to enforce this Agreement. 17. Survival of Restrictive Covenants and Other Provisions. Executive and the Company are parties to an Executive Employment Agreementdated as of [DATE] (the “Employment Agreement”). The Parties expressly acknowledge and agree that notwithstanding Paragraph 18 of this Agreement,Sections 8 (Non-Competition; Non-Solicitation; Anti-Raiding), 9 (Confidential Information), 10 (Equitable Remedies), and Sections 13-20 (to the extentrequired to interpret, enforce, and give effect to Sections 8, 9, and 10) of the Employment Agreement will continue in full force and effect; provided, however,that any provisions of the Employment Agreement that expire by their terms shall no longer have any force or effect. 18. Entire Agreement. Except as provided in Paragraph 17, this Agreement is the entire agreement between the Parties. Except as providedherein, this Agreement supersedes any and all prior oral or written promises or agreements between the Parties. Executive acknowledges that Executive hasnot relied on any promise, representation, or statement other than those set forth in this Agreement. This Agreement cannot be modified except in writingsigned by all Parties. 19. Interpretation. The determination of the terms of, and the drafting of, this Agreement has been by mutual agreement after negotiation, withconsideration by and participation of all Parties. Accordingly, the Parties agree that rules relating to the interpretation of contracts against the drafter of anyparticular clause shall not apply in the case of this Agreement. The term “Paragraph” shall refer to the enumerated paragraphs of this Agreement. Theheadings contained in this Agreement are for convenience of reference only and are not intended to limit the scope or affect the interpretation of anyprovision of this Agreement. 20. Choice of Law and Venue. This Agreement shall be construed and interpreted in accordance with the laws of the State of Colorado, withoutregard to its conflict of laws rules. Venue shall be in the Colorado state or federal courts. 21. Waiver. The failure of any Party to insist upon strict performance of any of the terms or conditions of this Agreement shall not constitute awaiver of any of such Party’s rights hereunder. 22. Counterparts. This Agreement may be executed in multiple counterparts, each of which shall be deemed an original, but all of whichtogether shall constitute one and the same instrument. [Signature Page Follows] 18 IN WITNESS WHEREOF, the Parties have executed this Confidential Severance and Release Agreement on the dates written below. EXECUTIVE ● Date THE COMPANY ● DateBy: Title: 19 Exhibit 10.85 RECOVERY ENERGY, INC.2012 EQUITY INCENTIVE PLANSTOCK OPTION AWARD AGREEMENT This Stock Option Award Agreement (the “Agreement”), is made as of the 14th day of April 2015, by and between Lilis Energy, Inc., aNevada corporation (the “Company”), and Ariella Fuchs (the “Participant”). WHEREAS, the Company desires to encourage and enable the Participant to acquire a proprietary interest in the Company throughownership of shares of the Company’s Common Stock, par value $0.0001 per share (the “Shares”), pursuant to the terms and conditions of the Company’s2012 Equity Incentive Plan (the “Plan”) and this Agreement. Such ownership will provide the Participant with additional incentive to promote the success ofthe Company; and WHEREAS, the Company and the Participant are parties to that certain Employment Agreement dated March 16, 2015 (the “EmploymentAgreement”). NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, theparties agree as follows: 1. Definitions. For purposes of this Agreement, all capitalized terms used herein and not otherwise defined herein shall have themeanings ascribed to them in the Plan. 2. Grant of Option. The Company hereby grants to the Participant options (the “Options”) to purchase up to 300,000 Shares at theexercise price (the “Exercise Price”) of $0.96 per Share, subject to the terms and conditions of this Agreement and the Plan. 3. Expiration Date. The Options granted hereby shall expire upon the ten year anniversary of the Effective Date (such date being the“Expiration Date”). Except as may be otherwise set forth herein, the Options may not be exercised after the Expiration Date. 4. Vesting. The Options shall vest and be exercisable by the Participant as follows: (a) Participant’s option to purchase 100,000 shares of Common Stock shall become exercisable on the first anniversary of theEffective Date (as defined in the Employment Agreement); (b) Participant’s option to purchase an additional 100,000 shares of Common Stock shall become exercisable on the secondanniversary of the Effective Date; and (c) Participant’s option to purchase an additional 100,000 shares of Common Stock shall become exercisable on the thirdanniversary of the Effective Date.  5. Separation from Service. (a) If the Participant’s employment is terminated by the Company for Cause (as defined in the Employment Agreement), thenall Options shall terminate. (b) If the Participant terminates his employment without Good Reason (as defined in the Employment Agreement), then allOptions shall terminate on the date that is 90 days after the date of termination of the Participant’s Continuous Service (as defined in the Plan), but not laterthan the Expiration Date. (c) In the event of Participant’s Disability (as defined in the Plan), the Participant may exercise the Options at any time withinone (1) year after the date of termination but not later than the Expiration Date. (d) In the event of Participant’s death or if a Participant should die within a period of 90 days after termination of theParticipant’s Continuous Service for reason other than Cause (as defined in the Plan), the personal representatives of the Participant’s estate or the person orpersons who shall have acquired the Options from the Participant by bequest or inheritance may exercise the Options at any time within one (1) year after thedate of death, but not later than the Expiration Date. 6. Sale, Merger or Dissolution. In the event of a Change in Control, the Company shall give the Participant notice thereof and theOptions, whether or not currently vested and exercisable, shall become immediately vested and exercisable immediately prior to the effective date of suchevent, and the Board shall have the power and discretion to provide alternatives regarding the terms and conditions for the exercise of, or modification of, theOptions in accordance with the Plan. 7. Non-Assignability. The Option granted hereby and any right arising thereunder may not be transferred, assigned, pledged orhypothecated (whether by operation of law or otherwise), except by will or the applicable laws of descent and distribution, and the Options and any rightsarising thereunder shall not be subject to execution, attachment or similar process. The Options shall be exercisable during the lifetime of the Participant onlyby the Participant. Any attempted assignment, transfer, pledge, hypothecation or other disposition of an Option not specifically permitted herein or in thePlan shall be null and void and without effect. 8. Mode of Exercise. (a) The Options may be exercised by delivery of an irrevocable notice of exercise in by the Participant to the Company,stating the number of shares being purchased. (b) The right to receive the Shares of the Company’s Common Stock upon exercise of the Options shall be conditioned uponthe delivery by the Participant of payment for shares and withholding taxes incurred by reason of the exercise and certain representations, if requested by theAdministrator. Acceptable forms of consideration for exercising the Options may include: (1) cash, check or wire transfer (denominated in U.S. Dollars); 2 (2) subject to the Company’s discretion to refuse for any reason and at any time to accept such consideration andsubject to any conditions or limitations established by the Administrator, other shares of the Company’s Common Stock held by the Participant which have aFair Market Value on the date of surrender equal to the aggregate exercise price of the Options to be exercised; (3) delivery of a notice that the Participant has placed a market sell order with a broker with respect to the Shares thenissuable upon exercise of the Options, and that the broker has been directed to pay a sufficient portion of the net proceeds of the sale to the Company insatisfaction of the aggregate payments required; provided, that payment of such proceeds is then made to the Company upon settlement of such sale; (4) subject to the Company’s discretion to refuse for any reason and at any time to accept such consideration andsubject to any conditions or limitations established by the Administrator, cashless “net exercise” arrangement pursuant to which the Company will reduce thenumber of shares issued upon exercise by the largest whole number of shares having an aggregate Fair Market Value that does not exceed the aggregateexercise price, together with required withholding amounts (if any), provided that the Company shall accept a cash or other payment from the Participant tothe extent of any remaining balance not satisfied by such reduction in the number of whole shares to be issued; (5) such other consideration and method of payment for the issuance of Shares of Common Stock to the extentpermitted by Applicable Laws and acceptable to the Administrator; and (6) any combination of the foregoing methods of payment. 9. Recapitalization. The number of Shares covered by the Options and the Exercise Price shall be proportionately adjusted for anyincrease or decrease in the number or type of issued Shares resulting from a stock split, reverse stock split, stock dividend, combination or reclassification ofthe Common Stock, or any other increase or decrease in the number of issued shares of Common Stock effected without receipt of consideration by theCompany. The conversion of any convertible securities of the Company shall not be deemed to have been “effected without receipt of consideration.” Suchadjustment shall be made by the Board, whose determination in that respect shall be final, binding and conclusive. 10. Plan Controlling. This Agreement is intended to conform in all respects with the requirements of the Plan. Inconsistencies betweenthe requirements of this Agreement and the Plan shall be resolved according to the terms of the Plan. The Participant acknowledges receipt of a copy of thePlan. 11. Rights Prior to Exercise of Option. The Participant shall not have any rights as a shareholder with respect to any Shares subject tothe Option prior to the date on which he is recorded as the holder of such Shares on the records of the Company. 3 12. Withholding Taxes. The Company shall have the right to require the Participant or his beneficiaries or legal representatives toremit to the Company an amount sufficient to satisfy any federal, state and local withholding tax requirements, including upon the grant, vesting or exerciseof this Option. Whenever payments under the Plan or this Agreement are to be made to any Participant in cash, such payments shall be net of any amountssufficient to satisfy all applicable taxes, including without limitation, all applicable federal, state and local withholding tax requirements to be withheld orsubmitted by the Company concerning such payments. The Board may, in its sole discretion, allow the Participant to satisfy withholding tax obligations byelecting to have the Company withhold from the Shares to be issued upon exercise of an Option that number of Shares having a Fair Market Value equal tothe minimum amount required to be withheld. The Fair Market Value of the Shares to be withheld shall be determined on the date that the amount of tax tobe withheld is to be determined. 13. Section 409A. The Options granted hereunder are intended to comply with or be exempt from the requirements of Code Section409A, and the Agreement shall be interpreted accordingly. In no event, however, shall the Company be liable to the Participant for any tax, penalties orinterest that may be due in respect of any the Options as a result of the application of Code Section 409A, except to the extent that such tax, penalty orinterest results from a breach of this Agreement by the Company. 14. Governing Law. This Agreement and all rights arising hereunder shall be governed by, and construed and interpreted inaccordance with, the laws of the State of Colorado. 15. Venue; Dispute Resolutions. This Agreement shall be subject to the venue and dispute resolution provisions set forth in Sections17 and 18 of the Employment Agreement. 4 NEITHER THE PLAN NOR THIS AGREEMENT SHALL BE CONSTRUED AS GIVING THE PARTICIPANT THE RIGHT TO BE RETAINED IN THEEMPLOY OR SERVICE OF THE COMPANY OR ANY AFFILIATE THEREOF, NOR SHALL THEY INTERFERE IN ANY WAY WITH THE RIGHT OF THECOMPANY OR ANY AFFILIATE THEREOF, AS APPLICABLE, TO TERMINATE THE PARTICIPANT’S EMPLOYMENT OR SERVICE AT ANY TIMEWITH OR WITHOUT CAUSE. * * * * * Executed as of the day and year first above written. LILIS ENERGY, INC. By:/s/ Abraham Mirman Name: Abraham Mirman Title: Chief Executive Officer PARTICIPANT By:/s/ Ariella Fuchs Ariella Fuchs 5Exhibit 10.87 RECOVERY ENERGY, INC.2012 EQUITY INCENTIVE PLANSTOCK OPTION AWARD AGREEMENT This Stock Option Award Agreement (the “Agreement”), is made as of the 14th day of April, by and between Lilis Energy, Inc., a Nevadacorporation (the “Company”), and Abraham Mirman (the “Participant”). WHEREAS, the Company desires to encourage and enable the Participant to acquire a proprietary interest in the Company throughownership of shares of the Company’s Common Stock, par value $0.0001 per share (the “Shares”), pursuant to the terms and conditions of the Company’s2012 Equity Incentive Plan (the “Plan”) and this Agreement. Such ownership will provide the Participant with additional incentive to promote the success ofthe Company; and WHEREAS, the Company and the Participant are parties to that certain Employment Agreement dated March 30, 2015 (the “EmploymentAgreement”). NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, theparties agree as follows: 1. Definitions. For purposes of this Agreement, all capitalized terms used herein and not otherwise defined herein shall have themeanings ascribed to them in the Plan. 2. Grant of Option. The Company hereby grants to the Participant options (the “Options”) to purchase up to 2,000,000 Shares at theexercise price (the “Exercise Price”) of $0.90 per Share, subject to the terms and conditions of this Agreement and the Plan. 3. Expiration Date. The Options granted hereby shall expire upon the ten year anniversary of Effective Date (such date being the“Expiration Date”). Except as may be otherwise set forth herein, the Options may not be exercised after the Expiration Date. 4. Vesting. The Options shall vest and be exercisable by the Participant as follows: (a) Participant’s option to purchase 666,667 shares of Common Stock shall become exercisable on the Effective Date (asdefined in the Employment Agreement); (b) Participant’s option to purchase an additional 666,667 shares of Common Stock shall become exercisable on the firstanniversary of the Effective Date; and (c) Participant’s option to purchase an additional 666,666 shares of Common Stock shall become exercisable on the secondanniversary of the Effective Date.  5. Separation from Service. (a) If the Participant’s employment is terminated by the Company for Cause (as defined in the Employment Agreement), thenall Options shall terminate. (b) If the Participant terminates his employment without Good Reason (as defined in the Employment Agreement), then allOptions shall terminate on the date that is 90 days after the date of termination of the Participant’s Continuous Service (as defined in the Plan), but not laterthan the Expiration Date. (c) In the event of Participant’s Disability (as defined in the Plan), the Participant may exercise the Options at any time withinone (1) year after the date of termination but not later than the Expiration Date. (d) In the event of Participant’s death or if a Participant should die within a period of 90 days after termination of theParticipant’s Continuous Service for reason other than Cause (as defined in the Plan), the personal representatives of the Participant’s estate or the person orpersons who shall have acquired the Options from the Participant by bequest or inheritance may exercise the Options at any time within one (1) year after thedate of death, but not later than the Expiration Date. 6. Sale, Merger or Dissolution. In the event of a Change in Control (as defined in the Employment Agreement), the Company shallgive the Participant notice thereof and the Options, whether or not currently vested and exercisable, shall become immediately vested and exercisableimmediately prior to the effective date of such event, and the Board shall have the power and discretion to provide alternatives regarding the terms andconditions for the exercise of, or modification of, the Options in accordance with the Plan. 7. Non-Assignability. The Option granted hereby and any right arising thereunder may not be transferred, assigned, pledged orhypothecated (whether by operation of law or otherwise), except by will or the applicable laws of descent and distribution, and the Options and any rightsarising thereunder shall not be subject to execution, attachment or similar process. The Options shall be exercisable during the lifetime of the Participant onlyby the Participant. Any attempted assignment, transfer, pledge, hypothecation or other disposition of an Option not specifically permitted herein or in thePlan shall be null and void and without effect. 8. Mode of Exercise. (a) The Options may be exercised by delivery of an irrevocable notice of exercise in by the Participant to the Company,stating the number of shares being purchased. (b) The right to receive the Shares of the Company’s Common Stock upon exercise of the Options shall be conditioned uponthe delivery by the Participant of payment for shares and withholding taxes incurred by reason of the exercise and certain representations, if requested by theAdministrator. Acceptable forms of consideration for exercising the Options may include: (1) cash, check or wire transfer (denominated in U.S. Dollars); 2 (2) subject to the Company’s discretion to refuse for any reason and at any time to accept such consideration andsubject to any conditions or limitations established by the Administrator, other shares of the Company’s Common Stock held by the Participant which have aFair Market Value on the date of surrender equal to the aggregate exercise price of the Options to be exercised; (3) delivery of a notice that the Participant has placed a market sell order with a broker with respect to the Shares thenissuable upon exercise of the Options, and that the broker has been directed to pay a sufficient portion of the net proceeds of the sale to the Company insatisfaction of the aggregate payments required; provided, that payment of such proceeds is then made to the Company upon settlement of such sale; (4) subject to the Company’s discretion to refuse for any reason and at any time to accept such consideration andsubject to any conditions or limitations established by the Administrator, cashless “net exercise” arrangement pursuant to which the Company will reduce thenumber of shares issued upon exercise by the largest whole number of shares having an aggregate Fair Market Value that does not exceed the aggregateexercise price, together with required withholding amounts (if any), provided that the Company shall accept a cash or other payment from the Participant tothe extent of any remaining balance not satisfied by such reduction in the number of whole shares to be issued; (5) such other consideration and method of payment for the issuance of Shares of Common Stock to the extentpermitted by Applicable Laws and acceptable to the Administrator; and (6) any combination of the foregoing methods of payment. 9. Recapitalization. The number of Shares covered by the Options and the Exercise Price shall be proportionately adjusted for anyincrease or decrease in the number or type of issued Shares resulting from a stock split, reverse stock split, stock dividend, combination or reclassification ofthe Common Stock, or any other increase or decrease in the number of issued shares of Common Stock effected without receipt of consideration by theCompany. The conversion of any convertible securities of the Company shall not be deemed to have been “effected without receipt of consideration.” Suchadjustment shall be made by the Board, whose determination in that respect shall be final, binding and conclusive. 10. Plan Controlling. This Agreement is intended to conform in all respects with the requirements of the Plan. Inconsistencies betweenthe requirements of this Agreement and the Plan shall be resolved according to the terms of the Plan. The Participant acknowledges receipt of a copy of thePlan. 11. Rights Prior to Exercise of Option. The Participant shall not have any rights as a shareholder with respect to any Shares subject tothe Option prior to the date on which he is recorded as the holder of such Shares on the records of the Company. 3 12. Withholding Taxes. The Company shall have the right to require the Participant or his beneficiaries or legal representatives toremit to the Company an amount sufficient to satisfy any federal, state and local withholding tax requirements, including upon the grant, vesting or exerciseof this Option. Whenever payments under the Plan or this Agreement are to be made to any Participant in cash, such payments shall be net of any amountssufficient to satisfy all applicable taxes, including without limitation, all applicable federal, state and local withholding tax requirements to be withheld orsubmitted by the Company concerning such payments. The Board may, in its sole discretion, allow the Participant to satisfy withholding tax obligations byelecting to have the Company withhold from the Shares to be issued upon exercise of an Option that number of Shares having a Fair Market Value equal tothe minimum amount required to be withheld. The Fair Market Value of the Shares to be withheld shall be determined on the date that the amount of tax tobe withheld is to be determined. 13. Section 409A. The Options granted hereunder are intended to comply with or be exempt from the requirements of Code Section409A, and the Agreement shall be interpreted accordingly. In no event, however, shall the Company be liable to the Participant for any tax, penalties orinterest that may be due in respect of any the Options as a result of the application of Code Section 409A, except to the extent that such tax, penalty orinterest results from a breach of this Agreement by the Company. 14. Governing Law. This Agreement and all rights arising hereunder shall be governed by, and construed and interpreted inaccordance with, the laws of the State of Colorado. 15. Venue; Dispute Resolutions. This Agreement shall be subject to the venue and dispute resolution provisions set forth in Sections17 and 18 of the Employment Agreement. 4 NEITHER THE PLAN NOR THIS AGREEMENT SHALL BE CONSTRUED AS GIVING THE PARTICIPANT THE RIGHT TO BE RETAINED IN THEEMPLOY OR SERVICE OF THE COMPANY OR ANY AFFILIATE THEREOF, NOR SHALL THEY INTERFERE IN ANY WAY WITH THE RIGHT OF THECOMPANY OR ANY AFFILIATE THEREOF, AS APPLICABLE, TO TERMINATE THE PARTICIPANT’S EMPLOYMENT OR SERVICE AT ANY TIMEWITH OR WITHOUT CAUSE. * * * * * Executed as of the day and year first above written. LILIS ENERGY, INC. By:/s/ Nuno Brandolini Name: Nuno Brandolini Title: Chairman of the Board PARTICIPANT By:/s/ Abraham Mirman Abraham Mirman 5Exhibit 21.1 Subsidiaries of the Registrant None. Exhibit 23.1 INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM’S CONSENT We consent to the incorporation by reference in the Registration Statement of Lilis Energy, Inc. on Form S-8 (File No. 333-185122) of our report dated April15, 2015, with respect to our audit of the financial statements of Lilis Energy, Inc. as of December 31, 2014 and for the year then ended, which report isincluded in this Annual Report on Form 10-K of Lilis Energy, Inc. for the year ended December 31, 2014. /s/ Marcum llp Marcum llpNew York, NYApril 15, 2015  Exhibit 23.2 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in the Registration Statement on Form S-8 (Registration No. 333-185122) of Lilis Energy, Inc. of our reportdated June 11, 2014 (except for Note 2, as to which the date is April 15, 2015), relating to our audit of the 2013 consolidated financial statements included inthe Annual Report on Form 10-K of Lilis Energy, Inc. for the year ended December 31, 2014. /s/ Hein & Associates LLP Denver, ColoradoApril 15, 2015 Exhibit 23.3 April 15, 2015 Lilis Energy, Inc.216 16th St, Suite #1350Denver, CO 80202 Attention: Abraham Mirman Dear Mr. Mirman: Ralph E. Davis Associates, Inc. here by consents to the reference to our firm in the form and context in which they appear in the Annual Report onForm 10-K of Lilis Energy, Inc. for the year ended December 31, 2014 (the “Annual Report”). We hereby further consent to the inclusion in the AnnualReport of estimates of oil and gas reserves contained in our report dated March 10, 2015, and to the inclusion of our report as an exhibit to the Annual Reportand in all current and future registration statements of the Company that incorporate by reference such Annual Report. Sincerely, RALPH E. DAVIS ASSOCIATES, INC. /s/ Allen C. Barron, P.E. Allen C. Barron, P.E. President 1717 St. James Place, Suite 460 Houston, Texas 77056 Office 713-622-8955 Fax 713-626-3664 www.ralphedavis.comWorldwide Energy Consultants Since 1924 Exhibit 31.1CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002I, Abraham Mirman, certify that:1.I have reviewed this Form 10-K of Lilis Energy, Inc.; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant's other certifying officer(s) and I Eire responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recentfiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant's internal control over financial reporting; and 5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b)Any fraud, whether or not material, that involved management or other employees who have a significant role in the registrant's internalcontrol over financial reporting. By:/s/Abraham Mirman Abraham Mirman Chief Executive Officer April 15, 2015 Exhibit 31.2CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002I, Kevin K. Nanke, certify that:1.I have reviewed this Form 10-K of Lilis Energy, Inc.; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recentfiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant's internal control over financial reporting; and 5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b)Any fraud, whether or not material, that involved management or other employees who have a significant role in the registrant's internalcontrol over financial reporting. By:/s/Kevin K. Nanke Kevin K. Nanke Executive Vice President and Chief Financial Officer April 15, 2015Exhibit 32.1 OFFICER'S CERTIFICATIONPURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002(18 U.S.C 1350) The undersigned, Abraham Mirman, the Chief Executive Officer of Lilis Energy, Inc., (the "Corporation"), in connection with the Corporation's Yearly Reporton Form 10-K for the year ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), does herebyrepresent, warrant and certify pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, as amended, that, to the best of his knowledge: 1.The Report is in full compliance with the reporting requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Corporation. By:/s/ Abraham Mirman Abraham Mirman Chief Executive Officer April 15, 2015 Exhibit 32.2OFFICER'S CERTIFICATIONPURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002(18 U.S.C 1350) The undersigned, Kevin K. Nanke, the Executive Vice President and Chief Financial Officer of Lilis Energy, Inc., (the "Corporation"), in connection with theCorporation's Yearly Report on Form 10-K for the year ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof(the "Report"), does hereby represent, warrant and certify pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, as amended, that, to the best of hisknowledge: 1.The Report is in full compliance with the reporting requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Corporation. By:/s/ Kevin K. Nanke Kevin K. Nanke Executive Vice President and Chief Financial Officer April 15, 2015Exhibit 99.1 LILIS ENERGY, INC. ESTIMATED RESERVESAND FUTURE NET REVENUE PROVED RESERVES As Of December 31, 2014  March 10, 2015 Lilis Energy, Inc.1900 Grant Street, Suite 720Denver, Colorado 80203 Attn:Mr. Abraham Mirman Chief Executive Officer Re: Estimated Reserves and Future Net Revenue,Lilis Energy, Inc.As of December 31, 2014 Gentlemen: At the request of Lilis Energy, Inc. (“Lilis”), the firm of Ralph E. Davis Associates, Inc. (“Davis”) of Houston, Texas has prepared an estimate of the oil andnatural gas reserves and future net revenue associated with specific leaseholds in which Lilis owns certain interests. The purpose of this report is to present asummary of the Proved Developed Producing and Undeveloped reserves that in our opinion meet the criteria for proved reserve volumes in keeping with thedirectives of the Securities and Exchange Commission as detailed later in this report. Davis has reviewed 100% of Lilis’s proved developed and undeveloped properties located in the Denver Julesberg Basin of the United States. This reportpresents our assessment of those reserves as of the effective date of this report, December 31, 2014, having completed the evaluation of said estimate ofreserves based upon the information presented within this report, on March 9, 2015. The reserves associated with this review have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Part210—Form and Content of and Requirements for Financial Statements, Securities Act of 1933, Securities Exchange Act of 1934, Public Utility HoldingCompany Act of 1935, Investment Company Act of 1940, Investment Advisers Act of 1940, and Energy Policy and Conservation Act of 1975, under Rules ofGeneral Application § 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and theEnergy Policy and Conservation Act of 1975. A summation of these definitions is included as a portion of this letter. We have also estimated the future net revenue and discounted present value associated with these reserves as of December 31, 2013 utilizing a scenario ofnon-escalated product prices as well as non-escalated costs of operations, i.e., prices and costs were not escalated above current values as detailed later in thisreport. The present value is presented for your information and should not be construed as an estimate of the fair market value. 1717 St. James Place, Suite 460 Houston, Texas 77056 Office 713-622-8955 Fax 713-626-3664 www.ralphedavis.comWorldwide Energy Consultants Since 1924 Estimated Reserves and Future Net RevenueMarch 10, 2015Lilis Energy, Inc.Page | 3As of December 31, 2014 The results of our study related to our estimate of the Total Proved Reserves attributable to Lilis and remaining to be produced as of December 31, 2014 are asfollows: Non Escalated Pricing ScenarioEstimated Reserves and Future Net IncomeNet to Lilis Energy, Inc.As of December 31, 2014 Producing Undeveloped Total Net Reserves Oil/Condensate-MBbls 50.2 849.5 899.7 Gas-MMCF 197.1 4,040.1 4,237.2 NGL-MBbls - - - Income Data (M$) Future Gross Revenue $5,476.5 $90,688.7 $96,165.3 Total Taxes $555.0 $7,422.8 $7,977.8 Operating Costs $1,370.7 $13,546.6 $14,917.3 Capital Costs $0.0 $28,388.2 $28,388.2 Future Net Income (FNI) $3,550.8 $41,331.2 $44,881.9 FNI @ 10% $2,340.5 $20,913.9 $23,254.4 Note: There may be differences in the addition as a result of computer program rounding of numbers. Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil. Gas volumes are expressed in millions of standard cubic feet (MMSCF) at theofficial temperature and pressure bases of the areas wherein the gas reserves are located. The economic cash flow presentation of the above volumes and revenues are presented for the individual reserve classifications, as well as appropriatesummaries, as Exhibit No. I. DISCUSSION The scope of this study was to prepare an estimate of the proved reserves attributable to Lilis’s ownership position in the subject properties. Reserve estimateswere prepared by Davis using acceptable evaluation principles for each source and were based in large part on the basic information supplied by Lilis. The quantities presented herein are estimated reserves of oil and natural gas volumes that geologic and engineering data demonstrate can be recovered fromknown reservoirs under current economic conditions with reasonable certainty. Proved undeveloped locations are scheduled to be drilled such that theinvestment cost will be fully recovered prior to recovery of the estimated reserve volume. Reserves classified as undeveloped are scheduled for future drillingbeginning in 2015. The undrilled locations have been reviewed on an individual well location basis. The estimates of these recoverable reserves are based onvolumetric estimates. Texas Registered Engineering Firm F-1529 Estimated Reserves and Future Net RevenueMarch 10, 2015Lilis Energy, Inc.Page | 4As of December 31, 2014 The estimated future net revenue and discounted present value associated with the reserves as of December 31, 2014 were prepared utilizing a pricingscenario that is detailed later in this report. This evaluation has been prepared in accordance with the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” asproclaimed by the Society of Petroleum Engineers, the SPE Standards. DATA SOURCE Basic well and field data used in the preparation of this report were furnished by Lilis or were obtained from commercial sources or from Davis’ own databaseof information. Records as they pertain to factual matters such as acreage controlled the number and depths of wells, reservoir pressure and productionhistory, the existence of contractual obligations to others and similar matters were accepted as presented. Additionally, the analyses of these properties utilized not only the basic data on the subject wells but also data on analogous properties as provided. Welllogs, ownership interest, revenues received from the sale of products and operating costs were furnished by Lilis Energy. No physical inspection of theproperties was made nor any well tests conducted at this time. Costs of operations were provided by Lilis or the operator of the properties on a well by well basis. These costs were reviewed by Davis and are considered tobe reasonable. Capital costs were also provided by Lilis, including drilling, completion and well stimulation costs anticipated as necessary to recoverestimated reserve volumes from new and existing wells. These costs were compared to actual costs of recently drilled wells, taking into account depth offuture wells to be drilled. The capital costs included in this report are also considered to be reasonable. OWNERSHIP Ownership interests in the subject properties have been furnished by Lilis Energy and accepted by Davis without independent verification. RESERVE ESTIMATES The estimate of reserves included in this report is based primarily upon production history or analogy with wells in the area producing from the same orsimilar formations. In addition to individual well production history, well test information when available was utilized in the evaluation. Geologic andseismic data were reviewed with Lilis personnel to establish reasonableness to the interpretations and a consistent basis for the volumetric estimates ofhydrocarbons originally in place in each of the respective field areas. Individual well production histories were analyzed and forecast until a calculatedeconomic limit. Texas Registered Engineering Firm F-1529 Estimated Reserves and Future Net RevenueMarch 10, 2015Lilis Energy, Inc.Page | 5As of December 31, 2014 Estimates of reserves to be recovered from undrilled locations are based upon not only the ultimate reserve of existing Lilis wells, but also completions byother operators in the area of interest. Studies of analogous completions have resulted in the development of an average completion than can be anticipatedfor a specific area, as well as a production profile that recovers the estimated ultimate reserve. This methodology has been utilized in this evaluation. Proved undeveloped reserves estimated for the Lang properties in which Lilis has a significant working interest position have increased substantially overthose volumes similarly booked in previous years. Prior to 2013 development of the Codell and Niobrara formations was scheduled to be accomplished by aseries of vertical wellbores on relatively tight spacing but with limited areal drainage. Development of the Lang area acreage, being the Bruegman andMojack wells, is scheduled to be accomplished by a series of horizontal wells drilled with a planned 5,000 foot lateral extension in each of the targetedNiobrara formations, and a 10,000 later in the Codell formation respectively. Horizontal well development of the Lang acreage will require separate wellbores for the Codell and Niobrara formations. Each well will also require Lilis topool it’s acreage with offset owners in order to effect multiple wellbores, each with either a 5,000 foot lateral extension or a 10,000 foot lateral, all to bedrilled from a single surface pad site. The result will be fewer wellbores with significantly increased recoverable reserves per wellbore in comparison to theprevious estimates of proved reserves. Estimates of proved reserves in the Sawyer acreage area in southeastern Wattenberg have become more defined in the past year with increased activity byoffset operators. Successful completions in offset acreage tracts have established both Niobrara and Codell as drillable proved locations on the Lilis acreage. Additional development potential was based upon geological interpretations; seismic indications of individual structures and well log analysis of knowindicators of production. Well spacing was based upon historical activity in the same reservoirs in nearby fields. In all cases, proved undeveloped locationswere limited to a direct offset to a proved developed producing well or unit or successful well test in the same reservoir. The accuracy of reserve estimates is dependent upon the quality of available data and upon the independent geological and engineering interpretation of thatdata. Reserve volumes presented in this report are based upon the available data and are calculated using all methods and procedures as we considerednecessary under the circumstances to prepare this report and are believed to be reasonable; however, future reservoir performance may justify revision of theseestimates. The various methods and procedures used in the evaluation of the subject properties are considered appropriate for an audit of the subjectproperties. It should be noted that all reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recoveredwill be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount ofreliable geological and engineering data available at the time of the estimate and the interpretation of these data. These reserves have been determined usingmethods and procedures widely accepted within the industry and are believed to be appropriate for the purposes of this report. In our opinion, we used allmethods and procedures necessary under the circumstances to prepare this report. Texas Registered Engineering Firm F-1529 Estimated Reserves and Future Net RevenueMarch 10, 2015Lilis Energy, Inc.Page | 6As of December 31, 2014 Regulations in the Oil and Gas industry are constantly changing to meet new safety and environmental concerns, in addition to the possibility of somemarket regulations which have occasionally occurred historically. State, Local or Federal Regulations, such as upon hydraulic fracturing, or drill/productionsite security and safety, environmental regulations of spills noxious emissions, greenhouse gases, and drill site location, wildlife protections and extensivepermitting processes, sometimes with multiple agencies or governments, in the future may all adversely affect the ability of the Registrant to recover theestimated reserves, as well as potentially rendering the reserves uneconomic, in certain, as yet undetermined, circumstances. To the best of the engineersbelief, none of the reserves described in this report are negatively impacted as of the date of this report, by any such current regulations. PRODUCING RATES For the purpose of this report, estimated reserves are scheduled for Lilis primarily on the basis of actual producing rates or appropriate well test information.They were prepared giving consideration to engineering and geological data such as reservoir pressure, anticipated producing mechanisms, the number andtypes of completions, as well as past performance of analogous reservoirs. These and other future rates may be subject to regulation by various agencies, changes in market demand or other factors; consequently, reserves recoveredand the actual rates of Lilis may vary from the estimates included herein. Scheduled dates of future well completions may vary from that provided by LilisEnergy due to changes in market demand or the availability of materials and/or capital; however, the timing of the wells and their estimated rates ofproduction are reasonable and consistent with established performance to date. PRICING PROVISIONS AND DIFFERENTIALS Prices utilized in the evaluation results presented in the letter portion of this report and summarized in the various tables included in this evaluation werefurnished by Lilis. Prices received for products sold, adjustments due to the BTU content of the gas, shrinkage for transportation, measuring or the removal ofliquids, the liquid yield from gas processed, etc., were accepted as presented. The unit price used throughout this report for crude oil, condensate and natural gas is based upon the appropriate price in effect the first trading of eachmonth during the previous twelve calendar months through December 2014, and averaged for the time period. Crude Oil and Condensate - The unit price used throughout this report for crude oil and condensate is based upon the average of prices for the previoustwelve months as indicated above. An average crude oil price for West Texas Intermediate crude of $94.56 per barrel was held constant throughout theproducing life of the properties. A pricing differential from this posted price was determined for the individual producing properties to account for locationand grade of crude based upon historical sales information and was utilized in this evaluation. This pricing differential was similarly held constant. Theaverage price realized for liquid reserves, crude oil and condensate, over the producing life of the properties, was $81.714 per barrel, and represents thecombined effect due to the adjustments for location and quality differentials such as transportation, quality and gravity. Prices for liquid reserves scheduledfor initial production at some future date were estimated using current prices on the same properties. Texas Registered Engineering Firm F-1529 Estimated Reserves and Future Net RevenueMarch 10, 2015Lilis Energy, Inc.Page | 7As of December 31, 2014 Natural Gas - The unit price used throughout this report for natural gas is based upon the average of prices for previous twelve months as indicated above. Anaverage gas price of $4.55 per MMBTU represented the Henry Hub BTU adjusted natural gas price and was held constant throughout the producing life ofthe properties. The average price realized for natural gas reserves over the producing life of the properties, was $5.344 per MLMBTU, and represents thecombined effect due to the adjustments for location and quality differentials such as transportation and the BTU (heating value) of the gas. Prices for gasreserves scheduled for initial production at some future date were estimated using this same price differential FUTURE NET INCOME Future net income is based upon gross income from future production, less direct operating expenses and taxes (production, severance, ad valorem or other).Estimated future capital for development and work-over costs was also deducted from gross income at the time it will be expended. No allowance was madefor depletion, depreciation, income taxes or administrative expense. Direct lease operating expense includes direct cost of operations of each lease or an estimated value for future operations based upon analogous properties.Lease operating expense and/or capital costs for drilling and/or major work over expense were not escalated throughout the remaining producing life of theproperties. Neither the cost to abandon properties nor the salvage value of equipment was considered in this report. Future net income has been discounted for present worth at values ranging from 0 to 100 percent using continuous discounting. In this report the future netincome is discounted at a primary rate of ten (10.0) percent. GENERAL Lilis Energy, Inc. has provided access to all of its accounts, records, geological and engineering data, reports and other information as required for thisevaluation. The ownership interests, product classifications relating to prices and other factual data were accepted as furnished without verification. No consideration was given in this report to either gas contract disputes including take or pay demands or gas sales imbalances. No consideration was given in this report to potential environmental liabilities which may exist, nor were any costs included for potential liability to restoreand clean up damages, if any, caused by past operating practices. Texas Registered Engineering Firm F-1529 Estimated Reserves and Future Net RevenueMarch 10, 2015Lilis Energy, Inc.Page | 8As of December 31, 2014 Neither Ralph E. Davis Associates, Inc. nor any of its employees have any interest in Lilis Energy Company, Inc. or any other related company or theproperties reported on herein. The employment and compensation to make this study are not contingent on our estimate of reserves. The technical personsresponsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality setforth in the SPE standards. This report has been prepared for public disclosure by Lilis Energy Company, Inc. in filings made with the SEC in accordance with the disclosurerequirements set forth in the SEC regulations. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please feel free to contact usif we can be of further service. We appreciate the opportunity to be of service to you in the matter of this report and will be glad to address any questions or inquiries you may have. Very truly yours, RALPH E. DAVIS ASSOCIATES, INC. \s\ Allen C. Barron, P.E. Allen C. Barron, P. E. President Texas Registered Engineering Firm F-1529 Securities and Exchange CommissionDefinitions of Reserves The following information is taken from the United States Securities and Exchange Commission: PART 210—FORM AND CONTENT OF AND REQUIREMENTS FOR FINANCIAL STATEMENTS, SECURITIES ACT OF 1933, SECURITIES EXCHANGE ACTOF 1934, PUBLIC UTILITY HOLDING COMPANY ACT OF 1935, INVESTMENT COMPANY ACT OF 1940, INVESTMENT ADVISERS ACT OF 1940, ANDENERGY POLICY AND CONSERVATION ACT OF 1975 Rules of General Application§ 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy andConservation Act of 1975. ReservesReserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, byapplication of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, thelegal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits andfinancing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated aseconomically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e.,absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resourcesfrom undiscovered accumulations). Proved Oil and Gas ReservesProved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonablecertainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods,and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonablycertain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must havecommenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economicallyproducible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetrationunless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap,proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliabletechnology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) areincluded in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of aninstalled program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of theengineering analysis on which the project or program was based; and(B) The project has been approved for development by all necessary parties and entities, including governmental entities.  Securities and Exchange CommissionPage 2§ 210.4-10 Definitions (of Reserves) Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be theaverage price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based uponfuture conditions. Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. Ifprobabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A highdegree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience(geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certainEUR is much more likely to increase or remain constant than to decrease. Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and hasbeen demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Probable ReservesProbable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likelyas not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plusprobable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceedthe proved plus probable reserves estimates. (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are lesscertain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may beassigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in placethan assumed for proved reserves. Possible ReservesPossible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plusprobable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recoveredwill equal or exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data areprogressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits ofcommercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recoveryquantities assumed for probable reserves. (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical andcommercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the sameaccumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and thathave not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir.Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the provedreservoir.  Securities and Exchange CommissionPage 3§ 210.4-10 Definitions (of Reserves) Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists foran associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact canbe established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may beassigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. Developed Oil and Gas ReservesDeveloped oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared tothe cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving awell. Undeveloped Oil and Gas ReservesUndeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wellswhere a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production whendrilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduledto be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or otherimproved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogousreservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. Additional Definitions: Deterministic EstimateThe method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economicdata) in the reserves calculation is used in the reserves estimation procedure. Probabilistic EstimateThe method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknownparameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. Reasonable CertaintyIf deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods areused, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists ifthe quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, andgeochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely toincrease or remain constant than to decrease.  LILIS ENERGY INCDATE: 03/09/2015 TOTAL PROVEDTIME: 15:59:28 AS OF 01/01/2015DBS: DEMO SEC NON-ESCALATED EVALUATIONSETTINGS: RED_JAN15 SCENARIO: RED_JAN15 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 01/2015 ENDMO- GROSS OILPRODUCTION GROSS GASPRODUCTION NET OILPRODUCTION NET GASPRODUCTION NET OILPRICE NET GASPRICE NET OILSALES NET GASSALES TOTALNETSALES YEAR MBBLS MMCF MBBLS MMCF $/BBL $/MCF M$ M$ M$ 12-2015 311.722 905.121 99.908 208.745 81.706 5.518 8163.110 1151.824 9314.934 12-2016 620.378 2005.275 237.637 692.994 81.669 5.321 19407.609 3687.244 23094.855 12-2017 289.364 1261.882 109.104 413.125 81.685 5.332 8912.186 2202.962 11115.149 12-2018 193.215 992.731 70.544 317.770 81.698 5.336 5763.245 1695.643 7458.887 12-2019 146.544 838.822 52.208 265.176 81.707 5.338 4265.753 1415.409 5681.163 12-2020 118.694 735.839 41.445 230.858 81.715 5.338 3386.707 1232.388 4619.096 12-2021 100.095 660.800 34.358 206.307 81.722 5.339 2807.831 1101.385 3909.216 12-2022 86.753 602.637 29.339 187.542 81.728 5.339 2397.801 1001.227 3399.027 12-2023 76.466 553.479 25.444 171.763 81.734 5.339 2079.604 917.013 2996.617 12-2024 67.063 510.048 21.946 157.847 81.741 5.339 1793.887 842.720 2636.608 12-2025 60.745 470.834 19.729 145.286 81.745 5.339 1612.743 775.648 2388.390 12-2026 55.342 434.853 17.866 133.740 81.749 5.339 1460.499 713.991 2174.490 12-2027 50.646 401.714 16.273 123.114 81.752 5.339 1330.319 657.250 1987.569 12-2028 46.393 371.128 14.792 113.333 81.756 5.338 1209.317 605.026 1814.343 12-2029 42.140 342.896 13.113 104.331 81.762 5.338 1072.179 556.958 1629.137 12-2030 38.866 316.835 12.072 96.046 81.764 5.338 987.050 512.716 1499.766 12-2031 35.849 292.777 11.113 88.419 81.767 5.338 908.707 471.994 1380.701 12-2032 33.068 270.566 10.231 81.400 81.769 5.338 836.596 434.512 1271.108 12-2033 30.504 250.060 9.419 74.938 81.772 5.338 770.220 400.013 1170.233 12-2034 28.141 231.126 8.672 68.991 81.774 5.338 709.123 368.257 1077.380 S TOT 2431.989 12449.424 855.211 3881.725 81.704 5.344 69874.492 20744.180 90618.680 AFTER 165.494 1463.318 44.516 355.516 81.897 5.347 3645.695 1900.900 5546.593 TOTAL 2597.482 13912.742 899.727 4237.241 81.714 5.344 73520.195 22645.080 96165.273  ENDMO- ADVALOREMTAX PRODUCTIONTAX DIRECTOPEREXPENSE INTERESTPAID CAPITALREPAYMENT EQUITYINVESTMENT FUTURE NETCASHFLOW CUMULATIVECASHFLOW CUM. DISC.CASHFLOW YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2015 739.186 31.194 191.447 0.000 0.000 27188.238 -18835.133 -18835.133 -17863.416 12-2016 1833.938 70.872 622.700 0.000 0.000 1200.000 19367.344 532.212 -1090.205 12-2017 875.523 71.071 640.427 0.000 0.000 0.000 9528.128 10060.340 6420.664 12-2018 588.077 44.825 638.102 0.000 0.000 0.000 6187.882 16248.222 10855.034 12-2019 448.338 31.953 636.708 0.000 0.000 0.000 4564.164 20812.387 13828.469 12-2020 364.856 24.256 635.871 0.000 0.000 0.000 3594.113 24406.500 15957.080 12-2021 309.051 19.138 635.369 0.000 0.000 0.000 2945.658 27352.158 17543.049 12-2022 268.935 15.509 635.068 0.000 0.000 0.000 2479.516 29831.674 18756.678 12-2023 237.415 12.017 623.547 0.000 0.000 0.000 2123.638 31955.312 19701.641 12-2024 209.610 6.846 573.056 0.000 0.000 0.000 1847.096 33802.406 20448.816 12-2025 189.928 5.938 573.056 0.000 0.000 0.000 1619.469 35421.875 21044.359 12-2026 172.954 5.220 573.056 0.000 0.000 0.000 1423.260 36845.137 21520.168 12-2027 158.112 4.640 573.056 0.000 0.000 0.000 1251.761 38096.895 21900.600 12-2028 144.447 3.637 565.856 0.000 0.000 0.000 1100.403 39197.301 22204.633 12-2029 130.176 0.807 529.856 0.000 0.000 0.000 968.299 40165.602 22447.842 12-2030 119.834 0.763 529.856 0.000 0.000 0.000 849.313 41014.910 22641.771 12-2031 110.317 0.722 529.856 0.000 0.000 0.000 739.807 41754.719 22795.340 12-2032 101.557 0.683 529.856 0.000 0.000 0.000 639.013 42393.730 22915.928 12-2033 93.494 0.646 529.856 0.000 0.000 0.000 546.237 42939.969 23009.637 12-2034 86.073 0.611 529.856 0.000 0.000 0.000 460.841 43400.809 23081.508 S TOT 7181.819 351.347 11296.454 0.000 0.000 28388.238 43400.809 43400.809 23081.508 AFTER 443.511 1.124 3620.826 0.000 0.000 0.000 1481.133 44881.945 23254.391 TOTAL 7625.330 352.471 14917.280 0.000 0.000 28388.238 44881.941 44881.945 23254.391 OIL GAS P.W. % P.W., M$ GROSS WELLS 22.0 0.0 LIFE, YRS. 39.25 5.00 31555.918 GROSS ULT., MB & MMF 2937.108 15739.652 DISCOUNT % 10.00 8.00 26163.836 GROSS CUM., MB & MMF 339.625 1826.910 UNDISCOUNTED PAYOUT, YRS. 1.97 10.00 23254.391 GROSS RES., MB & MMF 2597.483 13912.742 DISCOUNTED PAYOUT, YRS. 2.15 12.00 20758.898 NET RES., MB & MMF 899.727 4237.241 UNDISCOUNTED NET/INVEST. 2.58 15.00 17618.379 NET REVENUE, M$ 73520.188 22645.078 DISCOUNTED NET/INVEST. 1.87 18.00 15031.921 INITIAL PRICE, $ 81.718 5.377 RATE-OF-RETURN, PCT. 63.43 30.00 8068.712 INITIAL N.I., PCT. 11.459 4.895 INITIAL W.I., PCT. 45.903 60.00 440.802 80.00 -1826.590 260.00 -5558.546 Ralph E. Davis Associates, Inc.Texas Registered Engineering Firm F-1529 

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